UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 40-F
[Check one] | ||
¨ | REGISTRATION STATEMENT PURSUANT TO SECTION 12 OF THE SECURITIES EXCHANGE ACT OF 1934 | |
OR | ||
þ | ANNUAL REPORT PURSUANT TO SECTION 13(a) or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended: December 31, 2015 Commission File Number: 1-34513
CENOVUS ENERGY INC.
(Exact name of Registrant as specified in its charter)
Not applicable
(Translation of Registrants name into English (if applicable))
Canada
(Province or other jurisdiction of incorporation or organization)
1311
(Primary Standard Industrial
Classification Code Number (if applicable))
Not applicable
(I.R.S. Employer
Identification Number (if applicable))
2600, 500 Centre Street S.E.
Calgary, Alberta, Canada T2G 1A6
(403) 766-2000
(Address and telephone number of Registrants principal executive offices)
CT Corporation System
111 8th Avenue
New York, New York 10011
(212) 894-8641
(Name, address (including zip code) and telephone number (including area code)
of agent for service in the United States)
Securities registered or to be registered pursuant to Section 12(b) of the Act.
Title of each class | Name of each exchange on which registered | |
Common shares, no par value (together with associated common share purchase rights) |
New York Stock Exchange |
Securities registered or to be registered pursuant to Section 12(g) of the Act.
None
(Title of Class)
Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act.
None
(Title of Class)
For annual reports indicate by check mark the information filed with this Form:
þ Annual information form þ Audited annual financial statements
Indicate the number of outstanding shares of each of the issuers classes of capital or common stock as of the close of the period covered by the annual report:
833,289,845
Indicate by check mark whether the Registrant (1) has filed all reports to be filed by Section 13 or 15(d) of the Exchange Act during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports) and (2) has been subject to filing requirements for the past 90 days.
Yes þ No ¨
Indicate by check mark whether the Registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the Registrant was required to submit and post such files).
Yes ¨ No ¨
The annual report on Form 40-F shall be incorporated by reference into or as an exhibit to, as applicable, each of the Registrants Registration Statements under the Securities Act of 1933, as amended: Form S-8 (File No. 333-163397), Form F-3D (File No. 333-202165) and Form F-10 (File No. 333-196696).
Principal Documents
The following documents have been filed as part of this annual report on Form 40-F, beginning on the following page:
(a) | Annual Information Form of Cenovus Energy Inc. for the fiscal year ended December 31, 2015. |
(b) | Managements Discussion and Analysis of Cenovus Energy Inc. for the fiscal year ended December 31, 2015. |
(c) | Consolidated Financial Statements of Cenovus Energy Inc. for the fiscal year ended December 31, 2015. |
(d) | Supplementary Information Oil and Gas Activities (unaudited) for the fiscal year ended December 31, 2015. |
2
Cenovus Energy Inc.
Annual Information Form
For the Year Ended December 31, 2015
February 10, 2016
1 | ||||
3 | ||||
4 | ||||
7 | ||||
7 | ||||
10 | ||||
13 | ||||
14 | ||||
15 | ||||
20 | ||||
Significant Factors or Uncertainties Affecting Reserves Data |
21 | |||
21 | ||||
27 | ||||
27 | ||||
27 | ||||
28 | ||||
28 | ||||
28 | ||||
29 | ||||
33 | ||||
35 | ||||
37 | ||||
37 | ||||
37 | ||||
48 | ||||
48 | ||||
48 | ||||
48 | ||||
48 | ||||
49 | ||||
50 | ||||
APPENDIX A - Report on Reserves Data by Independent Qualified Reserves Evaluators |
A1 | |||
APPENDIX B - Report of Management and Directors on Reserves Data and Other Information |
B1 | |||
C1 |
Cenovus Energy Inc. |
2015 Annual Information Form |
1 | ||
Cenovus Energy Inc. |
2015 Annual Information Form |
2 | ||
Cenovus Energy Inc. |
2015 Annual Information Form |
INTERCORPORATE RELATIONSHIPS
Cenovuss material subsidiaries and partnerships as at December 31, 2015 are as follows:
Subsidiaries & Partnerships | Percentage Owned (1) |
Jurisdiction of Incorporation, Continuance, Formation or Organization | |||||
Cenovus FCCL Ltd. | 100 | Alberta | |||||
Cenovus Energy Marketing Services Ltd. | 100 | Alberta | |||||
Cenovus US Holdings Inc. | 100 | Delaware | |||||
FCCL Partnership (FCCL) (2) | 50 | Alberta | |||||
WRB Refining LP (WRB) (3) | 50 | Delaware |
(1) | Reflects all voting securities of all subsidiaries and partnerships beneficially owned, or controlled, or directed; directly or indirectly by Cenovus. |
(2) | Cenovus interest held through Cenovus FCCL Ltd., the operator and managing partner of FCCL. |
(3) | Cenovus interest held through Cenovus American Holdings Ltd. and Cenovus US Holdings Inc. |
The Corporations remaining subsidiaries and partnerships each account for (i) less than 10 percent of the Corporations consolidated assets as at December 31, 2015 and (ii) less than 10 percent of the Corporations consolidated revenues for the year ended December 31, 2015. In aggregate, Cenovuss unidentified subsidiaries and partnerships did not exceed 20 percent of the Corporations total consolidated assets or total consolidated revenues as at and for the year ended December 31, 2015.
3 | ||
Cenovus Energy Inc. |
2015 Annual Information Form |
GENERAL DEVELOPMENT OF THE BUSINESS
OVERVIEW
BUSINESS SEGMENTS
The Corporations reportable segments are as follows:
Oil Sands |
Includes the development and production of bitumen and natural gas in northeast Alberta. Cenovuss bitumen assets include Foster Creek, Christina Lake and Narrows Lake as well as projects in the early stages of development, such as Grand Rapids and Telephone Lake. Certain of Cenovuss operated oil sands properties, notably Foster Creek, Christina Lake and Narrows Lake, are jointly owned with ConocoPhillips, an unrelated U.S. public company. |
|||
Conventional |
Includes the development and production of conventional crude oil (1), NGLs and natural gas (2) in Alberta and Saskatchewan, including the heavy oil (3) assets at Pelican Lake, the carbon dioxide (CO2) enhanced oil recovery (EOR) project at Weyburn and emerging tight oil opportunities. |
|||
Refining and Marketing |
Includes transporting, selling and refining crude oil into petroleum and chemical products. Cenovus jointly owns two refineries in the U.S. with the operator Phillips 66, an unrelated U.S. public company. In addition, Cenovus owns and operates a crude-by-rail terminal in Alberta. This segment coordinates Cenovuss marketing and transportation initiatives to optimize product mix, delivery points, transportation commitments and customer diversification. |
|||
Corporate and Eliminations |
Primarily includes unrealized gains and losses recorded on derivative financial instruments, gains and losses on divestiture of assets, as well as other Cenovus-wide costs for general and administrative, financing activities and research costs. As financial instruments are settled, the realized gains and losses are recorded in the operating segment to which the derivative instrument relates. Eliminations relate to sales and operating revenues and purchased product between segments, recorded at transfer prices based on current market prices, and to unrealized intersegment profits in inventory. |
(1) | For the purpose of this AIF, references to crude oil means heavy crude oil and light crude oil and medium crude oil combined as those terms are defined in National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities. |
(2) | For the purpose of this AIF, references to natural gas means conventional natural gas as defined in National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities. |
(3) | For the purpose of this AIF, references to heavy oil means heavy crude oil as defined in National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities. |
4 | ||
Cenovus Energy Inc. |
2015 Annual Information Form |
THREE YEAR HISTORY
5 | ||
Cenovus Energy Inc. |
2015 Annual Information Form |
6 | ||
Cenovus Energy Inc. |
2015 Annual Information Form |
Landholdings
As at December 31, 2015, Cenovus held bitumen rights of approximately 1.8 million gross acres (1.5 million net acres) within the Athabasca and Cold Lake areas, as well as the exclusive rights to lease an additional 478,000 net acres on Cenovuss behalf and/or its assignees behalf on the Cold Lake Air Weapons Range.
The following table summarizes Cenovuss Oil Sands landholdings as at December 31, 2015, all of which are located within the Province of Alberta:
Developed Acreage |
Undeveloped Acreage |
Total Acreage |
Average Working Interest(1) |
|||||||||||||||||||||||||
|
|
|||||||||||||||||||||||||||
(thousands of acres) | Gross | Net | Gross | Net | Gross | Net | ||||||||||||||||||||||
|
||||||||||||||||||||||||||||
Foster Creek |
16 | 8 | 114 | 57 | 130 | 65 | 50% | |||||||||||||||||||||
Christina Lake |
9 | 4 | 49 | 24 | 58 | 28 | 50% | |||||||||||||||||||||
Narrows Lake |
- | - | 27 | 13 | 27 | 13 | 50% | |||||||||||||||||||||
Grand Rapids (2) |
- | - | 61 | 61 | 61 | 61 | 100% | |||||||||||||||||||||
Telephone Lake |
16 | 16 | 142 | 142 | 158 | 158 | 100% | |||||||||||||||||||||
Athabasca |
383 | 345 | 448 | 380 | 831 | 725 | 87% | |||||||||||||||||||||
Other |
29 | 11 | 1,459 | 1,173 | 1,488 | 1,184 | 79% | |||||||||||||||||||||
|
||||||||||||||||||||||||||||
Total |
453 | 384 | 2,300 | 1,850 | 2,753 | 2,234 | 81% | |||||||||||||||||||||
|
(1) | Percentages as represented in the above table cannot be calculated based on acreage shown due to rounding. |
(2) | Overlapping landholdings between Grand Rapids and Pelican Lake (included in the Conventional segment) have been allocated to Grand Rapids based on the projects approved development area. |
Production
The following table summarizes Cenovuss share of daily average production for the periods indicated:
Bitumen (bbls/d) |
Natural Gas (MMcf/d) |
Total Production (BOE/d) |
||||||||||||||||||||||
|
|
|||||||||||||||||||||||
(annual average) | 2015 | 2014 | 2015 | 2014 | 2015 | 2014 | ||||||||||||||||||
|
||||||||||||||||||||||||
Foster Creek |
65,345 | 59,172 | - | - | 65,345 | 59,172 | ||||||||||||||||||
Christina Lake |
74,975 | 69,023 | - | - | 74,975 | 69,023 | ||||||||||||||||||
Athabasca (1) |
- | - | 19 | 22 | 3,167 | 3,667 | ||||||||||||||||||
|
||||||||||||||||||||||||
Total |
140,320 | 128,195 | 19 | 22 | 143,487 | 131,862 | ||||||||||||||||||
|
(1) | Net of internal usage of natural gas used at Foster Creek to produce steam. |
7 | ||
Cenovus Energy Inc. |
2015 Annual Information Form |
Producing Wells
The following table summarizes Cenovuss interests in producing wells as at December 31, 2015. These figures exclude wells which were capable of producing, but that were not producing as at December 31, 2015:
Producing Bitumen Wells |
Producing Gas Wells |
Total Producing Wells |
||||||||||||||||||||||
|
|
|||||||||||||||||||||||
(number of wells) | Gross | Net | Gross | Net | Gross | Net | ||||||||||||||||||
|
||||||||||||||||||||||||
Foster Creek |
255 | 128 | - | - | 255 | 128 | ||||||||||||||||||
Christina Lake |
151 | 76 | - | - | 151 | 76 | ||||||||||||||||||
Grand Rapids |
2 | 2 | - | - | 2 | 2 | ||||||||||||||||||
Athabasca |
- | - | 316 | 303 | 316 | 303 | ||||||||||||||||||
Other |
3 | 3 | - | - | 3 | 3 | ||||||||||||||||||
|
||||||||||||||||||||||||
Total |
411 | 209 | 316 | 303 | 727 | 512 | ||||||||||||||||||
|
8 | ||
Cenovus Energy Inc. |
2015 Annual Information Form |
9 | ||
Cenovus Energy Inc. |
2015 Annual Information Form |
Landholdings
Developed Acreage | Undeveloped Acreage |
Total Acreage |
Average Interest (1) |
|||||||||||||||||||||||||
|
|
|||||||||||||||||||||||||||
(thousands of acres) | Gross | Net | Gross | Net | Gross | Net | ||||||||||||||||||||||
|
||||||||||||||||||||||||||||
Alberta |
||||||||||||||||||||||||||||
Grassland (2) |
959 | 920 | 32 | 27 | 991 | 947 | 96% | |||||||||||||||||||||
Suffield |
935 | 923 | 89 | 89 | 1,024 | 1,012 | 99% | |||||||||||||||||||||
Langevin (3) |
669 | 651 | 63 | 55 | 732 | 706 | 96% | |||||||||||||||||||||
Pelican Lake (4) |
95 | 94 | 254 | 241 | 349 | 335 | 96% | |||||||||||||||||||||
Wainwright |
49 | 29 | 13 | 9 | 62 | 38 | 63% | |||||||||||||||||||||
Other |
24 | 15 | 149 | 135 | 173 | 150 | 87% | |||||||||||||||||||||
Saskatchewan |
||||||||||||||||||||||||||||
Weyburn |
48 | 36 | 51 | 41 | 99 | 77 | 78% | |||||||||||||||||||||
Bakken |
4 | 4 | 48 | 48 | 52 | 52 | 98% | |||||||||||||||||||||
|
||||||||||||||||||||||||||||
Total |
2,783 | 2,672 | 699 | 645 | 3,482 | 3,317 | 95% | |||||||||||||||||||||
|
(1) | Percentages as represented in the above table cannot be calculated based on acreage shown due to rounding. |
(2) | Grassland is located in the Drumheller and Brooks areas. |
(3) | Langevin is located northwest of Medicine Hat. |
(4) | Overlapping landholdings between Grand Rapids (included in the Oil Sands segment) and Pelican Lake have been allocated to Grand Rapids based on the projects approved development area. |
10 | ||
Cenovus Energy Inc. |
2015 Annual Information Form |
Production
The following table summarizes Cenovuss share of daily average production (1) for the periods indicated:
Crude Oil and NGLs (bbls/d) |
Natural Gas (MMcf/d) |
Total Production (BOE/d) |
||||||||||||||||||||||
|
|
|||||||||||||||||||||||
(annual average) | 2015 | 2014 | 2015 | 2014 | 2015 | 2014 | ||||||||||||||||||
|
||||||||||||||||||||||||
Alberta |
||||||||||||||||||||||||
Grassland (2) |
7,248 | 8,923 | 212 | 232 | 42,581 | 47,590 | ||||||||||||||||||
Suffield |
8,854 | 10,010 | 125 | 135 | 29,687 | 32,510 | ||||||||||||||||||
Langevin (3) |
8,025 | 9,368 | 84 | 96 | 22,025 | 25,368 | ||||||||||||||||||
Pelican Lake |
24,421 | 24,924 | - | - | 24,421 | 24,924 | ||||||||||||||||||
Wainwright (4) |
1,638 | 4,687 | 1 | 2 | 1,805 | 5,020 | ||||||||||||||||||
Other |
10 | 8 | - | - | 10 | 8 | ||||||||||||||||||
Saskatchewan |
||||||||||||||||||||||||
Weyburn |
15,732 | 16,196 | - | - | 15,732 | 16,196 | ||||||||||||||||||
Bakken (4) |
699 | 1,182 | - | 1 | 699 | 1,349 | ||||||||||||||||||
Other |
- | - | - | - | - | - | ||||||||||||||||||
|
||||||||||||||||||||||||
Total |
66,627 | 75,298 | 422 | 466 | 136,960 | 152,965 | ||||||||||||||||||
|
(1) | Includes production from mineral fee title lands in which Cenovus has a working interest and mineral fee title lands in which Cenovus has retained a royalty interest. In the third quarter of 2015, Cenovus sold those royalty interests. |
(2) | Grassland is located in the Drumheller and Brooks areas. |
(3) | Langevin is located northwest of Medicine Hat. |
(4) | Cenovus sold certain interests in its Bakken and Wainwright crude oil assets in the second and third quarter of 2014, respectively. Cenovus retained royalty interests on mineral fee title lands in these areas. In the third quarter of 2015, Cenovus sold those royalty interests. |
Producing Wells
The following table summarizes Cenovuss interests in producing wells (1) as at December 31, 2015. These figures exclude wells which were capable of producing, but that were not producing, as at December 31, 2015:
Producing Oil Wells |
Producing Gas Wells |
Total Producing Wells |
||||||||||||||||||||||
|
|
|||||||||||||||||||||||
(number of wells) | Gross | Net | Gross | Net | Gross | Net | ||||||||||||||||||
|
||||||||||||||||||||||||
Alberta |
||||||||||||||||||||||||
Grassland (2) |
398 | 391 | 8,804 | 8,660 | 9,202 | 9,051 | ||||||||||||||||||
Suffield |
739 | 739 | 10,676 | 10,658 | 11,415 | 11,397 | ||||||||||||||||||
Langevin (3) |
300 | 298 | 4,752 | 4,740 | 5,052 | 5,038 | ||||||||||||||||||
Pelican Lake |
587 | 587 | 1 | 1 | 588 | 588 | ||||||||||||||||||
Wainwright |
57 | 52 | 10 | 2 | 67 | 54 | ||||||||||||||||||
Other |
10 | 5 | 2 | 1 | 12 | 6 | ||||||||||||||||||
Saskatchewan |
||||||||||||||||||||||||
Weyburn |
644 | 405 | - | - | 644 | 405 | ||||||||||||||||||
Bakken |
9 | 2 | - | - | 9 | 2 | ||||||||||||||||||
Other |
1 | 1 | 1 | 1 | ||||||||||||||||||||
|
||||||||||||||||||||||||
Total |
2,745 | 2,480 | 24,245 | 24,062 | 26,990 | 26,542 | ||||||||||||||||||
|
(1) | Includes wells on mineral fee title lands where Cenovus has a working interest. Excludes wells on mineral fee title lands where Cenovus only has a royalty interest. In the third quarter of 2015, Cenovus sold those royalty interests. |
(2) | Grassland is located in the Drumheller and Brooks areas. |
(3) | Langevin is located northwest of Medicine Hat. |
11 | ||
Cenovus Energy Inc. |
2015 Annual Information Form |
Net Wells Drilled and Production
The following table summarizes net oil wells drilled and daily average oil production figures (1) for the periods indicated:
Average Production (2) (bbls/d) |
||||||||||||||||||||||||
|
|
|||||||||||||||||||||||
Net Wells Drilled | Light & Medium Oil | Heavy Oil | ||||||||||||||||||||||
|
|
|||||||||||||||||||||||
2015 | 2014 | 2015 | 2014 | 2015 | 2014 | |||||||||||||||||||
|
||||||||||||||||||||||||
Alberta |
||||||||||||||||||||||||
Grassland (3) |
15 | 42 | 6,632 | 8,224 | - | - | ||||||||||||||||||
Suffield |
1 | 18 | - | - | 8,837 | 9,991 | ||||||||||||||||||
Langevin (4) |
12 | 29 | 7,858 | 9,221 | - | - | ||||||||||||||||||
Wainwright (5) |
- | 4 | 1 | 42 | 1,630 | 4,631 | ||||||||||||||||||
Pelican Lake |
- | 25 | - | - | 24,421 | 24,924 | ||||||||||||||||||
Other |
- | 1 | 10 | 8 | - | - | ||||||||||||||||||
Saskatchewan |
||||||||||||||||||||||||
Weyburn |
6 | 7 | 15,343 | 15,921 | - | - | ||||||||||||||||||
Bakken (5) |
- | - | 642 | 1,115 | - | - | ||||||||||||||||||
Other |
- | - | - | - | - | - | ||||||||||||||||||
|
||||||||||||||||||||||||
Total |
34 | 126 | 30,486 | 34,531 | 34,888 | 39,546 | ||||||||||||||||||
|
(1) | Excludes wells drilled by third parties on mineral fee title lands. In the third quarter of 2015, Cenovus sold those fee lands. |
(2) | Includes production from mineral fee title lands in which Cenovus has a working interest and mineral fee title lands in which Cenovus had retained a royalty interest. In the third quarter of 2015, Cenovus sold those fee lands. |
(3) | Grassland landholdings are located in the Drumheller and Brooks areas. |
(4) | Langevin landholdings are located northwest of Medicine Hat. |
(5) | Cenovus sold certain interests in its Bakken and Wainwright crude oil assets in the second and third quarter of 2014, respectively. Cenovus retained royalty interests on mineral fee title lands in these areas. In the third quarter of 2015, Cenovus sold those royalty interests. |
12 | ||
Cenovus Energy Inc. |
2015 Annual Information Form |
The following table summarizes the key operational results for the refineries in the periods indicated:
Refinery Operations (1) | 2015 | 2014 | ||||||
|
||||||||
Crude Oil Capacity (Mbbls/d) |
460 | 460 | ||||||
Crude Oil Runs (Mbbls/d) |
419 | 423 | ||||||
Heavy Oil |
200 | 199 | ||||||
Light & Medium Oil |
219 | 224 | ||||||
|
||||||||
Crude Utilization (%) |
91 | 92 | ||||||
|
||||||||
Refined Products (Mbbls/d) |
||||||||
Gasoline |
228 | 231 | ||||||
Distillates |
137 | 137 | ||||||
Other |
79 | 77 | ||||||
|
||||||||
Total |
444 | 445 | ||||||
|
(1) | Represents 100 percent of the Wood River and Borger Refinery operations. |
13 | ||
Cenovus Energy Inc. |
2015 Annual Information Form |
RESERVES DATA AND OTHER OIL AND GAS INFORMATION
(1) | For the purpose of this AIF, references to light and medium oil means light crude oil and medium crude oil combined as defined in National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities. |
14 | ||
Cenovus Energy Inc. |
2015 Annual Information Form |
Summary of Company Interest Oil and Gas Reserves as at December 31, 2015
(Forecast prices and inflation)
Before Royalties | Bitumen (MMbbls) |
Heavy Oil (MMbbls) |
Light & Medium Oil & NGLs (MMbbls) |
Natural Gas & CBM (Bcf) |
||||||||||||
|
||||||||||||||||
Proved Reserves |
||||||||||||||||
Developed Producing |
268 | 103 | 89 | 703 | ||||||||||||
Developed Non-Producing |
54 | 1 | 2 | 14 | ||||||||||||
Undeveloped |
1,861 | 29 | 19 | 4 | ||||||||||||
|
||||||||||||||||
Proved Reserves |
2,183 | 133 | 110 | 721 | ||||||||||||
|
||||||||||||||||
Probable Reserves |
1,115 | 87 | 44 | 232 | ||||||||||||
|
||||||||||||||||
Proved plus Probable Reserves |
3,298 | 220 | 154 | 953 | ||||||||||||
|
||||||||||||||||
After Royalties (1) | Bitumen (MMbbls) |
Heavy Oil (MMbbls) |
Light & Medium Oil & NGLs (MMbbls) |
Natural Gas & CBM (Bcf) |
||||||||||||
|
||||||||||||||||
Proved Reserves |
||||||||||||||||
Developed Producing |
223 | 84 | 69 | 658 | ||||||||||||
Developed Non-Producing |
43 | 1 | 1 | 13 | ||||||||||||
Undeveloped |
1,428 | 25 | 16 | 3 | ||||||||||||
|
||||||||||||||||
Proved Reserves |
1,694 | 110 | 86 | 674 | ||||||||||||
|
||||||||||||||||
Probable Reserves |
862 | 67 | 33 | 206 | ||||||||||||
|
||||||||||||||||
Proved plus Probable Reserves |
2,556 | 177 | 119 | 880 | ||||||||||||
|
(1) | As a result of Cenovuss sale in 2015 of HRP, Cenovuss royalty interest and mineral fee title lands business, Cenovus no longer discloses royalty interest reserves separately. |
Summary of Net Present Value of Future Net Revenue as at December 31, 2015 (1)
(Forecast prices and inflation)
Discounted at %/year ($ millions) | Unit Value Discounted at 10% (2) |
|||||||||||||||||||||||||
|
|
|
|
|||||||||||||||||||||||
Before Income Taxes | 0% | 5% | 10% | 15% | 20% | $/BOE | ||||||||||||||||||||
|
|
|
||||||||||||||||||||||||
Proved Reserves |
||||||||||||||||||||||||||
Developed Producing |
4,868 | 6,453 | 5,992 | 5,361 | 4,798 | 12.34 | ||||||||||||||||||||
Developed Non-Producing |
1,308 | 993 | 776 | 622 | 509 | 16.40 | ||||||||||||||||||||
Undeveloped |
50,517 | 20,376 | 9,538 | 4,917 | 2,657 | 6.49 | ||||||||||||||||||||
|
|
|
||||||||||||||||||||||||
Proved Reserves |
56,693 | 27,822 | 16,306 | 10,900 | 7,964 | 8.15 | ||||||||||||||||||||
Probable Reserves |
35,624 | 12,105 | 5,260 | 2,763 | 1,642 | 5.28 | ||||||||||||||||||||
|
|
|
||||||||||||||||||||||||
Proved plus Probable Reserves |
92,317 | 39,927 | 21,566 | 13,663 | 9,606 | 7.19 | ||||||||||||||||||||
|
|
|
Discounted at %/year ($ millions) | ||||||||||||||||||||
|
|
|||||||||||||||||||
After Income Taxes (3) | 0% | 5% | 10% | 15% | 20% | |||||||||||||||
|
||||||||||||||||||||
Proved Reserves |
||||||||||||||||||||
Developed Producing |
3,455 | 5,358 | 5,110 | 4,637 | 4,192 | |||||||||||||||
Developed Non-Producing |
939 | 734 | 588 | 481 | 401 | |||||||||||||||
Undeveloped |
36,922 | 15,077 | 7,110 | 3,685 | 2,002 | |||||||||||||||
|
||||||||||||||||||||
Proved Reserves |
41,316 | 21,169 | 12,808 | 8,803 | 6,595 | |||||||||||||||
|
||||||||||||||||||||
Probable Reserves |
26,583 | 9,021 | 3,900 | 2,038 | 1,208 | |||||||||||||||
|
||||||||||||||||||||
Proved plus Probable Reserves |
67,899 | 30,190 | 16,708 | 10,841 | 7,803 | |||||||||||||||
|
(1) | Due to amendments to NI 51-101 effective July 1, 2015 (the 2015 Amendments), abandonment and reclamation costs included in the calculation of the NPV and FNR for 2015 are different than abandonment and reclamation costs included in Cenovuss 2014 disclosure of NPV and FNR. The 2015 Amendments require that all abandonment and reclamation costs be included in the calculation of NPV and FNR including all existing estimated abandonment and reclamation costs, plus all forecast estimates of abandonment and reclamation costs attributable to future development activity associated with the reserves. |
(2) | Unit values have been calculated using Company Interest After Royalties reserves. |
(3) | Values are calculated by considering existing tax pools and tax circumstances for Cenovus and its subsidiaries in the consolidated evaluation of Cenovuss oil and gas properties, and take into account current federal tax regulations. Values do not represent an estimate of the value at the business entity level, which may be significantly different. For information at the business entity level, please see the Corporations Consolidated Financial Statements and Managements Discussion and Analysis for the year ended December 31, 2015. |
15 | ||
Cenovus Energy Inc. |
2015 Annual Information Form |
Total Future Net Revenue (undiscounted) as at December 31, 2015
(Forecast prices and inflation - $ millions)
Reserves Category |
Revenue | Royalties | Operating Costs |
Development Costs |
Total Abandonment and Reclamation Costs (1) |
Future Net Revenue Before Future Income Taxes |
Future Income Taxes |
Future Net Revenue After Future Income Taxes |
||||||||||||||||||||||||
Proved Reserves |
176,710 | 40,459 | 51,293 | 19,671 | 8,594 | 56,693 | 15,377 | 41,316 | ||||||||||||||||||||||||
Proved plus Probable Reserves |
282,430 | 65,067 | 80,663 | 34,178 | 10,205 | 92,317 | 24,418 | 67,899 |
(1) | Total abandonment and reclamation costs included for all wells, facilities and other liabilities, known and existing, and to be incurred as a result of future development activity. |
Future Net Revenue by Product Type as at December 31, 2015
(Forecast prices and inflation)
Reserves Category | Product Types | Future Net Revenue Before Income Taxes (discounted at 10%/year) ($ millions) |
Unit Value Discounted at 10%/year (1) ($/BOE) |
|||||||
Proved Reserves |
Bitumen |
14,288 | 8.44 | |||||||
Heavy Oil |
1,057 | 9.64 | ||||||||
Light & Medium Oil and NGLs |
1,146 | 13.37 | ||||||||
Natural Gas |
(185 | ) | (1.65 | ) | ||||||
Total |
16,306 | 8.15 | ||||||||
Proved plus Probable Reserves | Bitumen |
18,146 | 7.10 | |||||||
Heavy Oil |
1,684 | 9.54 | ||||||||
Light & Medium Oil and NGLs |
1,699 | 14.27 | ||||||||
Natural Gas |
37 | 0.25 | ||||||||
Total |
21,566 | 7.19 |
(1) | Unit values have been calculated using Company Interest After Royalties reserves. |
16 | ||
Cenovus Energy Inc. |
2015 Annual Information Form |
17 | ||
Cenovus Energy Inc. |
2015 Annual Information Form |
Pricing Assumptions
The forecast of prices and inflation (the McDaniel Forecast) provided in the table below was obtained from McDaniel and used to estimate FNR associated with the reserves disclosed herein. The McDaniel Forecast is dated January 1, 2016. The inflation forecast was applied uniformly to prices beyond the forecast interval, and to all future costs. For historical prices realized during 2015, see Production History in this AIF.
Oil | Natural Gas & CBM |
|||||||||||||||||||||||||||||||||||
Year | WTI Cushing Oklahoma (US$/bbl) |
Edmonton Par Price 40 API (C$/bbl) |
Cromer Medium 29.3 API (C$/bbl) |
Alberta Heavy 12 API (C$/bbl) |
Western Canadian Select (C$/bbl) |
AECO Gas Price (C$/MMBtu) |
Inflation Rate (%/year) |
Exchange Rate (US$/C$) |
||||||||||||||||||||||||||||
2016 |
45.00 | 56.60 | 52.60 | 40.50 | 46.40 | 2.70 | 0.0 | 0.730 | ||||||||||||||||||||||||||||
2017 |
53.60 | 66.40 | 61.80 | 47.50 | 54.40 | 3.20 | 2.0 | 0.750 | ||||||||||||||||||||||||||||
2018 |
62.40 | 72.80 | 67.70 | 52.10 | 59.70 | 3.55 | 2.0 | 0.800 | ||||||||||||||||||||||||||||
2019 |
69.00 | 80.90 | 75.20 | 57.80 | 66.30 | 3.85 | 2.0 | 0.800 | ||||||||||||||||||||||||||||
2020 |
73.10 | 83.20 | 77.40 | 59.50 | 68.20 | 3.95 | 2.0 | 0.825 | ||||||||||||||||||||||||||||
2021 |
77.30 | 88.20 | 82.00 | 63.10 | 72.30 | 4.20 | 2.0 | 0.825 | ||||||||||||||||||||||||||||
2022 |
81.60 | 93.30 | 86.80 | 66.70 | 76.50 | 4.45 | 2.0 | 0.825 | ||||||||||||||||||||||||||||
2023 |
86.20 | 98.70 | 91.80 | 70.60 | 80.90 | 4.70 | 2.0 | 0.825 | ||||||||||||||||||||||||||||
2024 |
87.90 | 100.70 | 93.70 | 72.00 | 82.60 | 4.80 | 2.0 | 0.825 | ||||||||||||||||||||||||||||
2025 |
89.60 | 102.60 | 95.40 | 73.40 | 84.10 | 4.90 | 2.0 | 0.825 | ||||||||||||||||||||||||||||
2026 |
91.40 | 104.70 | 97.40 | 74.90 | 85.90 | 5.00 | 2.0 | 0.825 | ||||||||||||||||||||||||||||
There-after |
+2%/yr | +2%/yr | +2%/yr | +2%/yr | +2%/yr | +2%/yr | 2.0 | 0.825 |
Future Development Costs
The following table outlines undiscounted future development costs deducted in the estimation of FNR calculated utilizing forecast prices and inflation for the years indicated:
Reserves Category
($ millions) | 2016 | 2017 | 2018 | 2019 | 2020 | Remainder | Total | |||||||||||||||||||||
Proved Reserves |
534 | 980 | 860 | 1,073 | 934 | 15,290 | 19,671 | |||||||||||||||||||||
Proved plus Probable Reserves |
593 | 1,308 | 1,378 | 1,445 | 1,103 | 28,351 | 34,178 |
18 | ||
Cenovus Energy Inc. |
2015 Annual Information Form |
Reserves Reconciliation
The following tables provide a reconciliation of Cenovuss Company Interest Before Royalties reserves for bitumen, heavy oil, light and medium oil and NGLs, and natural gas and CBM for the year ended December 31, 2015, presented using forecast prices and inflation. All reserves are located in Canada.
Proved | Bitumen (MMbbls) |
Heavy Oil (MMbbls) |
Light & Medium Oil & NGLs (MMbbls) |
Natural Gas & CBM (Bcf) |
||||||||||||
As at December 31, 2014 |
1,970 | 156 | 120 | 796 | ||||||||||||
Extensions and Improved Recovery |
188 | - | 1 | 8 | ||||||||||||
Discoveries |
- | - | - | - | ||||||||||||
Technical Revisions |
76 | (10 | ) | 1 | 79 | |||||||||||
Economic Factors |
- | - | (1 | ) | (1 | ) | ||||||||||
Acquisitions |
- | - | - | - | ||||||||||||
Dispositions |
- | - | - | - | ||||||||||||
Production (1) |
(51 | ) | (13 | ) | (11 | ) | (161 | ) | ||||||||
As at December 31, 2015 |
2,183 | 133 | 110 | 721 | ||||||||||||
Probable | Bitumen (MMbbls) |
Heavy Oil (MMbbls) |
Light & Medium Oil & NGLs (MMbbls) |
Natural Gas & CBM (Bcf) |
||||||||||||
As at December 31, 2014 |
1,330 | 123 | 46 | 260 | ||||||||||||
Extensions and Improved Recovery |
- | - | 1 | 7 | ||||||||||||
Discoveries |
- | - | - | - | ||||||||||||
Technical Revisions |
(215 | ) | (36 | ) | (4 | ) | (36 | ) | ||||||||
Economic Factors |
- | - | 1 | 1 | ||||||||||||
Acquisitions |
- | - | - | - | ||||||||||||
Dispositions |
- | - | - | - | ||||||||||||
Production (1) |
- | - | - | - | ||||||||||||
As at December 31, 2015 |
1,115 | 87 | 44 | 232 | ||||||||||||
Proved plus Probable | Bitumen (MMbbls) |
Heavy Oil (MMbbls) |
Light & Medium Oil & NGLs (MMbbls) |
Natural Gas & CBM (Bcf) |
||||||||||||
As at December 31, 2014 |
3,300 | 279 | 166 | 1,056 | ||||||||||||
Extensions and Improved Recovery |
188 | - | 2 | 15 | ||||||||||||
Discoveries |
- | - | - | - | ||||||||||||
Technical Revisions |
(139 | ) | (46 | ) | (3 | ) | 43 | |||||||||
Economic Factors |
- | - | - | - | ||||||||||||
Acquisitions |
- | - | - | - | ||||||||||||
Dispositions |
- | - | - | - | ||||||||||||
Production (1) |
(51 | ) | (13 | ) | (11 | ) | (161 | ) | ||||||||
As at December 31, 2015 |
3,298 | 220 | 154 | 953 |
(1) | Production used for the reserves reconciliation differs from publicly reported production. In accordance with NI 51-101, Company Interest Before Royalties production used for the reserves reconciliation above includes Cenovuss share of gas volumes provided to FCCL for steam generation, but does not include Royalty Interest production. |
19 | ||
Cenovus Energy Inc. |
2015 Annual Information Form |
Company Interest Proved Undeveloped Before Royalties
Bitumen (MMbbls) |
Heavy Oil (MMbbls) |
Light & Medium Oil & NGLs (MMbbls) |
Natural Gas & CBM (Bcf) |
|||||||||||||||||||||||||||||
First Attributed |
Total at Year-End |
First Attributed |
Total at Year-End |
First Attributed |
Total at Year-End |
First Attributed |
Total at Year-End |
|||||||||||||||||||||||||
Prior |
1,717 | 1,532 | 93 | 61 | 56 | 22 | 300 | 6 | ||||||||||||||||||||||||
2013 |
158 | 1,629 | 1 | 47 | 3 | 15 | - | 4 | ||||||||||||||||||||||||
2014 |
161 | 1,732 | 7 | 40 | 11 | 21 | 4 | 4 | ||||||||||||||||||||||||
2015 |
238 | 1,861 | - | 29 | 1 | 19 | 1 | 4 |
Company Interest Probable Undeveloped Before Royalties
Bitumen (MMbbls) |
Heavy Oil (MMbbls) |
Light & Medium Oil & NGLs (MMbbls) |
Natural Gas & CBM (Bcf) |
|||||||||||||||||||||||||||||
First Attributed |
Total at Year-End |
First Attributed |
Total at Year-End |
First Attributed |
Total at Year-End |
First Attributed |
Total at Year-End |
|||||||||||||||||||||||||
Prior |
1,099 | 646 | 66 | 42 | 34 | 24 | 54 | 16 | ||||||||||||||||||||||||
2013 |
145 | 649 | 56 | 86 | 1 | 17 | - | 16 | ||||||||||||||||||||||||
2014 |
649 | 1,293 | 5 | 76 | 8 | 15 | 7 | 11 | ||||||||||||||||||||||||
2015 |
1 | 1,074 | - | 52 | 1 | 14 | 2 | 8 |
DEVELOPMENT OF PROVED AND PROBABLE UNDEVELOPED RESERVES
20 | ||
Cenovus Energy Inc. |
2015 Annual Information Form |
SIGNIFICANT FACTORS OR UNCERTAINTIES AFFECTING RESERVES DATA
Oil and Gas Properties and Wells
The following tables summarize Cenovuss interests in producing and non-producing wells, as at December 31, 2015:
Oil | Gas | Total | ||||||||||||||||||||||
Producing Wells (1) | Gross | Net | Gross | Net | Gross | Net | ||||||||||||||||||
Alberta |
||||||||||||||||||||||||
Oil Sands |
411 | 209 | 316 | 303 | 727 | 512 | ||||||||||||||||||
Conventional |
2,091 | 2,072 | 24,245 | 24,062 | 26,336 | 26,134 | ||||||||||||||||||
Total Alberta |
2,502 | 2,281 | 24,561 | 24,365 | 27,063 | 26,646 | ||||||||||||||||||
Saskatchewan |
654 | 408 | - | - | 654 | 408 | ||||||||||||||||||
Total |
3,156 | 2,689 | 24,561 | 24,365 | 27,717 | 27,054 |
(1) | Includes wells containing multiple completions as follows: 22,174 gross gas wells (22,013 net wells) and 1,318 gross oil wells (1,073 net wells). |
Oil | Gas | Total | ||||||||||||||||||||||
Non-Producing Wells (1) | Gross | Net | Gross | Net | Gross | Net | ||||||||||||||||||
Alberta |
||||||||||||||||||||||||
Oil Sands |
61 | 33 | 343 | 246 | 404 | 279 | ||||||||||||||||||
Conventional |
785 | 769 | 971 | 940 | 1,756 | 1,709 | ||||||||||||||||||
Total Alberta |
846 | 802 | 1,314 | 1,186 | 2,160 | 1,988 | ||||||||||||||||||
Saskatchewan |
205 | 92 | 5 | 5 | 210 | 97 | ||||||||||||||||||
Total |
1,051 | 894 | 1,319 | 1,191 | 2,370 | 2,085 |
(1) | Non-producing wells include wells which are capable of producing, but which are currently not producing. Non-producing wells do not include other types of wells such as stratigraphic test wells, service wells, or wells that have been abandoned. |
Cenovus has no properties with attributed reserves which are capable of producing, but which are not on production.
21 | ||
Cenovus Energy Inc. |
2015 Annual Information Form |
Exploration and Development Activity
The following tables summarize Cenovuss gross participation and net interest in wells drilled in 2015 (1):
Oil Sands |
Conventional |
Total | ||||||||||||||||||||||
|
|
|||||||||||||||||||||||
Development Wells Drilled |
Gross | Net | Gross | Net | Gross | Net | ||||||||||||||||||
|
||||||||||||||||||||||||
Oil |
96 | 49 | 35 | 32 | 131 | 81 | ||||||||||||||||||
Gas |
- | - | - | - | - | - | ||||||||||||||||||
Dry & Abandoned |
- | - | 1 | 1 | 1 | 1 | ||||||||||||||||||
|
||||||||||||||||||||||||
Total Working Interest |
96 | 49 | 36 | 33 | 132 | 82 | ||||||||||||||||||
Royalty |
- | - | 1 | - | 1 | - | ||||||||||||||||||
|
||||||||||||||||||||||||
Total Canada |
96 | 49 | 37 | 33 | 133 | 82 | ||||||||||||||||||
|
(1) | Cenovus did not have any participation or interest in any exploration wells in 2015. |
During the year ended December 31, 2015, Oil Sands drilled 164 gross stratigraphic test wells (73 net wells) and Conventional drilled 13 gross stratigraphic test wells (13 net wells).
During the year ended December 31, 2015, Oil Sands drilled eight gross service wells (four net wells) and Conventional drilled three gross service wells (1.8 net wells). 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 were focused on sustaining bitumen production at Foster Creek and Christina Lake, and on supporting our EOR projects at Pelican Lake and Weyburn.
Interest in Material Properties
The following table summarizes Cenovuss landholdings as at December 31, 2015:
Landholdings | ||||||||||||||||||||||||
(thousands of acres) | Developed Acreage | Undeveloped Acreage (1) | Total Acreage | |||||||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||
Alberta: |
||||||||||||||||||||||||
Oil Sands |
||||||||||||||||||||||||
Crown (2) |
453 | 384 | 2,236 | 1,786 | 2,689 | 2,170 | ||||||||||||||||||
Conventional |
||||||||||||||||||||||||
Crown (2) |
1,065 | 1,019 | 530 | 490 | 1,595 | 1,509 | ||||||||||||||||||
Freehold (3) |
1,666 | 1,613 | 70 | 66 | 1,736 | 1,679 | ||||||||||||||||||
Total Alberta |
3,184 | 3,016 | 2,836 | 2,342 | 6,020 | 5,358 | ||||||||||||||||||
Saskatchewan: |
||||||||||||||||||||||||
Oil Sands |
||||||||||||||||||||||||
Crown (2) |
- | - | 64 | 64 | 64 | 64 | ||||||||||||||||||
Conventional |
||||||||||||||||||||||||
Crown (2) |
35 | 28 | 95 | 87 | 130 | 115 | ||||||||||||||||||
Freehold (3) |
17 | 12 | 4 | 2 | 21 | 14 | ||||||||||||||||||
Total Saskatchewan |
52 | 40 | 163 | 153 | 215 | 193 | ||||||||||||||||||
Total |
3,236 | 3,056 | 2,999 | 2,495 | 6,235 | 5,551 |
(1) | Undeveloped includes land that has not yet been drilled, as well as land with wells that have never produced hydrocarbons or that do not currently allow for the production of hydrocarbons. |
(2) | Crown/Federal lands are those lands owned by the federal or provincial government or the First Nations, in which Cenovus holds a working interest. |
(3) | Freehold lands are those lands owned by individuals and other entities (other than a government) in which Cenovus holds a working interest. |
22 | ||
Cenovus Energy Inc. |
2015 Annual Information Form |
Costs Incurred
($ millions) | 2015 | |||
|
||||
Acquisitions |
||||
Unproved |
4 | |||
Proved |
- | |||
|
||||
Total Acquisitions |
4 | |||
Exploration Costs |
66 | |||
Development Costs |
1,360 | |||
|
||||
Total Costs Incurred |
1,430 | |||
|
Forward Contracts
Cenovus may use financial derivatives to manage its exposure to fluctuations in commodity prices, foreign exchange and interest rates. A description of such instruments is provided in the notes to the Corporations annual audited Consolidated Financial Statements for the year ended December 31, 2015.
23 | ||
Cenovus Energy Inc. |
2015 Annual Information Form |
Production Estimates
The following table summarizes the estimated 2016 average daily volume of Company Working Interest Before Royalties reflected in the reserves reports for all properties held on December 31, 2015 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.
2016 Estimated Production
Forecast Prices and Costs |
Proved | Proved plus Probable |
||||||
Bitumen (bbls/d) (1) |
152,517 | 159,881 | ||||||
Light and Medium Oil (bbls/d) |
28,265 | 32,060 | ||||||
Heavy Oil (bbls/d) |
31,727 | 32,946 | ||||||
Natural Gas (MMcf/d) |
357 | 390 | ||||||
Natural Gas Liquids (bbls/d) |
658 | 732 | ||||||
Company Working Interest Before Royalties (BOE/d) |
272,715 | 290,620 |
(1) | Includes Foster Creek production of 74,929 barrels per day for proved and 77,581 barrels per day for proved plus probable, and Christina Lake production of 77,588 barrels per day for proved and 82,300 barrels per day for proved plus probable. |
Production History
Average Working Interest Daily Production Volumes - 2015 | ||||||||||||||||||||
Year | Q4 | Q3 | Q2 | Q1 | ||||||||||||||||
|
||||||||||||||||||||
Crude Oil and Natural Gas Liquids (bbls/d) |
||||||||||||||||||||
Oil Sands |
||||||||||||||||||||
Foster Creek (Bitumen) |
65,345 | 63,680 | 71,414 | 58,363 | 67,901 | |||||||||||||||
Christina Lake (Bitumen) |
74,975 | 75,733 | 75,329 | 72,371 | 76,471 | |||||||||||||||
|
||||||||||||||||||||
140,320 | 139,413 | 146,743 | 130,734 | 144,372 | ||||||||||||||||
Conventional Liquids |
||||||||||||||||||||
Heavy Oil |
34,260 | 32,363 | 33,693 | 34,790 | 36,244 | |||||||||||||||
Light and Medium Oil |
28,607 | 26,576 | 27,551 | 28,886 | 31,481 | |||||||||||||||
Natural Gas Liquids (1) |
1,148 | 1,154 | 1,130 | 1,139 | 1,171 | |||||||||||||||
|
||||||||||||||||||||
Total Crude Oil and Natural Gas Liquids |
204,335 | 199,506 | 209,117 | 195,549 | 213,268 | |||||||||||||||
|
||||||||||||||||||||
Natural Gas (MMcf/d) |
||||||||||||||||||||
Oil Sands |
19 | 19 | 19 | 21 | 20 | |||||||||||||||
Conventional |
412 | 405 | 405 | 415 | 423 | |||||||||||||||
|
||||||||||||||||||||
Total Natural Gas |
431 | 424 | 424 | 436 | 443 | |||||||||||||||
|
||||||||||||||||||||
Total (BOE/d) |
276,168 | 270,173 | 279,784 | 268,216 | 287,101 | |||||||||||||||
|
||||||||||||||||||||
(1) Natural gas liquids include condensate volumes. |
||||||||||||||||||||
Average Royalty Interest Daily Production Volumes - 2015 |
||||||||||||||||||||
Year | Q4 | Q3 | Q2 | Q1 | ||||||||||||||||
|
||||||||||||||||||||
Crude Oil and Natural Gas Liquids (bbls/d) |
||||||||||||||||||||
Conventional Liquids (1) |
||||||||||||||||||||
Heavy Oil |
628 | - | 304 | 1,309 | 911 | |||||||||||||||
Light and Medium Oil |
1,879 | 49 | 940 | 2,923 | 3,654 | |||||||||||||||
Natural Gas Liquids (2) |
105 | 1 | 61 | 173 | 187 | |||||||||||||||
|
||||||||||||||||||||
Total Crude Oil and Natural Gas Liquids |
2,612 | 50 | 1,305 | 4,405 | 4,752 | |||||||||||||||
|
||||||||||||||||||||
Natural Gas (MMcf/d) |
||||||||||||||||||||
Conventional |
10 | - | 6 | 14 | 19 | |||||||||||||||
|
||||||||||||||||||||
Total (BOE/d) |
4,279 | 50 | 2,305 | 6,738 | 7,919 | |||||||||||||||
|
(1) | Cenovus sold the majority of its royalty interest and mineral fee title lands in the third quarter of 2015. |
(2) | Natural gas liquids include condensate volumes. |
24 | ||
Cenovus Energy Inc. |
2015 Annual Information Form |
Per-Unit Results
The following tables summarize Cenovuss per-unit results, as well as the impact of realized financial hedging, on a quarterly basis, before deduction of royalties, for the periods indicated:
Per-Unit Results 2015 (excluding impact of realized gain (loss) on risk management) |
Year | Q4 | Q3 | Q2 | Q1 | |||||||||||||||
Bitumen - Foster Creek ($/bbl) (1) (2) (3) |
||||||||||||||||||||
Price |
33.65 | 25.09 | 33.35 | 48.25 | 29.42 | |||||||||||||||
Royalties |
0.47 | 0.12 | 0.20 | 1.97 | (0.25 | ) | ||||||||||||||
Transportation and blending |
8.84 | 8.53 | 8.50 | 9.04 | 9.39 | |||||||||||||||
Operating expenses |
12.60 | 11.66 | 11.27 | 13.29 | 14.50 | |||||||||||||||
Netback |
11.74 | 4.78 | 13.38 | 23.95 | 5.78 | |||||||||||||||
Bitumen - Christina Lake ($/bbl) (1) (2) (3) |
||||||||||||||||||||
Price |
28.45 | 21.34 | 27.46 | 43.36 | 23.30 | |||||||||||||||
Royalties |
0.67 | 0.30 | 0.83 | 0.99 | 0.61 | |||||||||||||||
Transportation and blending |
4.72 | 5.40 | 5.00 | 4.29 | 4.17 | |||||||||||||||
Operating expenses |
8.01 | 7.80 | 7.80 | 8.20 | 8.24 | |||||||||||||||
Netback |
15.05 | 7.84 | 13.83 | 29.88 | 10.28 | |||||||||||||||
Total Bitumen - Oil Sands ($/bbl) (1) (2) (3) |
||||||||||||||||||||
Price |
30.88 | 23.08 | 30.35 | 45.61 | 26.04 | |||||||||||||||
Royalties |
0.58 | 0.22 | 0.52 | 1.44 | 0.22 | |||||||||||||||
Transportation and blending |
6.64 | 6.85 | 6.72 | 6.48 | 6.50 | |||||||||||||||
Operating expenses |
10.13 | 9.59 | 9.46 | 10.57 | 10.99 | |||||||||||||||
Netback |
13.53 | 6.42 | 13.65 | 27.12 | 8.33 | |||||||||||||||
Heavy Crude Oil - Conventional ($/bbl) (1) (2) (3) |
||||||||||||||||||||
Price |
39.95 | 32.84 | 37.09 | 52.63 | 35.85 | |||||||||||||||
Royalties |
2.97 | 2.24 | 1.73 | 5.34 | 2.34 | |||||||||||||||
Transportation and blending |
3.36 | 3.63 | 3.36 | 3.09 | 3.42 | |||||||||||||||
Operating expenses |
15.92 | 15.20 | 15.59 | 15.45 | 17.30 | |||||||||||||||
Production and mineral taxes |
0.04 | (0.03 | ) | 0.07 | 0.08 | 0.02 | ||||||||||||||
Netback |
17.66 | 11.80 | 16.34 | 28.67 | 12.77 | |||||||||||||||
Total Bitumen and Heavy Crude Oil ($/bbl) (1) (2) (3) |
||||||||||||||||||||
Price |
32.73 | 24.87 | 31.63 | 47.24 | 28.15 | |||||||||||||||
Royalties |
1.07 | 0.59 | 0.75 | 2.35 | 0.68 | |||||||||||||||
Transportation and blending |
5.97 | 6.26 | 6.08 | 5.69 | 5.83 | |||||||||||||||
Operating expenses |
11.31 | 10.62 | 10.62 | 11.70 | 12.35 | |||||||||||||||
Production and mineral taxes |
0.01 | (0.01 | ) | 0.01 | 0.02 | - | ||||||||||||||
Netback |
14.37 | 7.41 | 14.17 | 27.48 | 9.29 |
(1) Netbacks do not reflect non-cash write-downs of product inventory. (2) Cost of condensate per barrel of unblended crude oil ($/bbl). (3) Employee long-term incentive costs were reclassified from operating expenses to general and administrative costs. |
Bitumen and heavy crude oil price and transportation and blending costs exclude the costs of purchased condensate, which is blended with the bitumen and heavy crude oil. On a per-barrel of unblended bitumen and heavy crude oil basis, the cost of condensate is as follows: |
|
||||||||||||||||||||
Bitumen Foster Creek ($/bbl) |
27.44 | 25.96 | 24.20 | 29.82 | 30.57 | |||||||||||||||
Bitumen Christina Lake ($/bbl) |
29.50 | 27.39 | 26.42 | 32.90 | 31.60 | |||||||||||||||
Bitumen Oil Sands ($/bbl) |
28.54 | 26.72 | 25.33 | 31.48 | 31.14 | |||||||||||||||
Heavy Crude Oil Conventional ($/bbl) |
10.94 | 9.99 | 9.56 | 12.42 | 11.50 | |||||||||||||||
Total Bitumen and Heavy Crude Oil ($/bbl) |
24.94 | 23.64 | 22.34 | 27.06 | 26.91 | |||||||||||||||
|
25 | ||
Cenovus Energy Inc. |
2015 Annual Information Form |
Per-Unit Results 2015 | ||||||||||||||||||||
(excluding impact of realized gain (Loss) on risk management) | Year | Q4 | Q3 | Q2 | Q1 | |||||||||||||||
Light and Medium Crude Oil ($/bbl) (1) |
||||||||||||||||||||
Price |
50.64 | 45.35 | 49.57 | 61.66 | 45.81 | |||||||||||||||
Royalties |
5.66 | 6.97 | 7.02 | 5.67 | 3.56 | |||||||||||||||
Transportation and blending |
2.91 | 2.80 | 2.88 | 3.06 | 2.88 | |||||||||||||||
Operating expenses |
16.27 | 17.37 | 15.92 | 15.90 | 16.04 | |||||||||||||||
Production and mineral taxes |
1.41 | 0.76 | 1.60 | 1.95 | 1.28 | |||||||||||||||
Netback |
24.39 | 17.45 | 22.16 | 35.08 | 22.05 | |||||||||||||||
Total Bitumen and Crude Oil (Heavy, Light and Medium) ($/bbl) (1) (2) |
||||||||||||||||||||
Price |
35.41 | 27.62 | 34.08 | 49.55 | 31.09 | |||||||||||||||
Royalties |
1.75 | 1.44 | 1.60 | 2.88 | 1.16 | |||||||||||||||
Transportation and blending |
5.51 | 5.79 | 5.64 | 5.27 | 5.34 | |||||||||||||||
Operating expenses |
12.05 | 11.52 | 11.35 | 12.37 | 12.97 | |||||||||||||||
Production and mineral taxes |
0.22 | 0.10 | 0.23 | 0.33 | 0.22 | |||||||||||||||
Netback |
15.88 | 8.77 | 15.26 | 28.70 | 11.40 | |||||||||||||||
Natural Gas Liquids ($/bbl) |
||||||||||||||||||||
Price |
30.98 | 30.70 | 24.57 | 39.64 | 28.51 | |||||||||||||||
Royalties |
1.74 | 3.94 | 1.75 | 0.87 | 0.66 | |||||||||||||||
Netback |
29.24 | 26.76 | 22.82 | 38.77 | 27.85 | |||||||||||||||
Total Bitumen, Crude Oil (Heavy, Light and Medium) and Natural Gas Liquids ($/bbl) (1) (2) |
||||||||||||||||||||
Price |
35.38 | 27.63 | 34.03 | 49.48 | 31.08 | |||||||||||||||
Royalties |
1.75 | 1.46 | 1.60 | 2.86 | 1.16 | |||||||||||||||
Transportation and blending |
5.48 | 5.76 | 5.61 | 5.24 | 5.31 | |||||||||||||||
Operating expenses |
11.98 | 11.46 | 11.28 | 12.29 | 12.89 | |||||||||||||||
Production and mineral taxes |
0.22 | 0.10 | 0.23 | 0.33 | 0.22 | |||||||||||||||
Netback |
15.95 | 8.85 | 15.31 | 28.76 | 11.50 | |||||||||||||||
Total Natural Gas ($/Mcf) (1) |
||||||||||||||||||||
Price |
2.92 | 2.78 | 3.00 | 2.82 | 3.05 | |||||||||||||||
Royalties |
0.07 | 0.10 | 0.11 | 0.03 | 0.05 | |||||||||||||||
Transportation and blending |
0.11 | 0.11 | 0.10 | 0.10 | 0.12 | |||||||||||||||
Operating expenses |
1.20 | 1.25 | 1.16 | 1.14 | 1.26 | |||||||||||||||
Production and mineral taxes |
0.01 | 0.02 | 0.01 | 0.02 | 0.01 | |||||||||||||||
Netback |
1.53 | 1.30 | 1.62 | 1.53 | 1.61 | |||||||||||||||
Total ($/BOE) (1) (2) |
||||||||||||||||||||
Price |
30.67 | 24.78 | 29.95 | 40.50 | 27.73 | |||||||||||||||
Royalties |
1.40 | 1.23 | 1.36 | 2.13 | 0.93 | |||||||||||||||
Transportation and blending |
4.21 | 4.43 | 4.35 | 3.95 | 4.11 | |||||||||||||||
Operating expenses |
10.72 | 10.43 | 10.18 | 10.78 | 11.49 | |||||||||||||||
Production and mineral taxes |
0.18 | 0.10 | 0.19 | 0.27 | 0.17 | |||||||||||||||
Netback |
14.16 | 8.59 | 13.87 | 23.37 | 11.03 | |||||||||||||||
(1) Employee long-term incentive costs were reclassified from operating expenses to general and administrative costs. (2) Netbacks do not reflect non-cash write-downs of product inventory.
|
|
|||||||||||||||||||
Impact of Realized Gain (Loss) on Risk Management 2015 | Year | Q4 | Q3 | Q2 | Q1 | |||||||||||||||
Liquids ($/bbl) |
7.51 | 11.39 | 10.07 | 1.75 | 6.58 | |||||||||||||||
Natural Gas ($/Mcf) |
0.37 | 0.42 | 0.37 | 0.39 | 0.29 | |||||||||||||||
Total ($/BOE) |
6.11 | 9.08 | 8.07 | 1.92 | 5.31 |
26 | ||
Cenovus Energy Inc. |
2015 Annual Information Form |
Capital Expenditures, Acquisitions and Divestitures
Cenovus has a large inventory of internal growth opportunities and continues to examine select acquisition opportunities to develop and expand its oil and gas properties. Acquisition opportunities may include corporate or asset acquisitions. Cenovus may finance any such acquisitions with debt, equity, cash generated from operations, proceeds from asset divestitures or a combination of these sources.
2015: Cenovus has an active program to divest its non-core assets in order to increase its focus on key assets within the long range business plan, as well as generate proceeds to partially fund its capital investment. In the third quarter, Cenovus sold HRP, the holder of its royalty interest and mineral fee title lands business in Alberta, Saskatchewan and Manitoba to an unrelated third party for gross cash proceeds of $3.3 billion. Also in the third quarter, Cenovus acquired the Bruderheim rail terminal, a crude-by-rail terminal at Bruderheim, Alberta for $75 million plus adjustments.
2014: Early in the second quarter, Cenovus completed the sale of certain of its Bakken assets for net proceeds of $35 million. Immediately prior to the disposition, the properties were producing an average of 396 barrels per day during the first quarter of 2014. Late in the third quarter, Cenovus also completed the sale of certain Wainwright properties for net proceeds of $234 million. The properties were producing an average of 2,775 barrels per day during the first nine months of 2014.
The following table summarizes Cenovuss net capital investment for 2015 and 2014:
Net Capital Investment | ||||||||
($ millions) | 2015 | 2014 | ||||||
|
||||||||
Capital Investment |
||||||||
Oil Sands |
||||||||
Foster Creek |
403 | 796 | ||||||
Christina Lake |
647 | 794 | ||||||
|
||||||||
Total |
1,050 | 1,590 | ||||||
Other Oil Sands |
135 | 396 | ||||||
|
||||||||
1,185 | 1,986 | |||||||
Conventional |
244 | 840 | ||||||
|
||||||||
Refining and Marketing |
248 | 163 | ||||||
Corporate |
37 | 62 | ||||||
|
||||||||
Capital Investment |
1,714 | 3,051 | ||||||
|
||||||||
Acquisitions |
87 | 18 | ||||||
Divestitures |
(3,344 | ) | (277) | |||||
|
||||||||
Net Acquisition and Divestiture Activity |
(3,257 | ) | (259) | |||||
|
||||||||
Net Capital Investment (1) |
(1,543 | ) | 2,792 | |||||
|
(1) | Includes expenditures on PP&E and E&E. |
27 | ||
Cenovus Energy Inc. |
2015 Annual Information Form |
The following table summarizes Cenovuss full-time equivalent (FTE) employees as at December 31, 2015:
FTE Employees | ||||
|
||||
Upstream |
2,001 | |||
Downstream |
127 | |||
Corporate |
877 | |||
|
||||
Total |
3,005 | |||
|
Cenovus also engages a number of contractors and service providers. Refer to Risk Factors - Operational Risks - Leadership and Talent for further information on employee matters affecting Cenovus.
Cenovus, and its reportable segments, are not dependent upon foreign operations outside North America. As a result, the Corporations exposure to risks and uncertainties in countries considered politically and economically unstable is limited. Any future operations outside North America may be adversely affected by changes in government policy, social instability or other political or economic developments which are not within Cenovuss control, including the expropriation of property, the cancellation or modification of contract rights and restrictions on repatriation of cash. Refer to Risk Factors Financial Risks Foreign Exchange Rates for information on foreign exchange rate matters affecting Cenovus.
28 | ||
Cenovus Energy Inc. |
2015 Annual Information Form |
DIRECTORS AND EXECUTIVE OFFICERS
DIRECTORS
The following individuals are directors of Cenovus.
Name and Residence |
Director Since (1) |
Principal Occupation During the Past Five Years | ||
Ralph S. Cunningham (3,4,6) Houston, Texas, United States |
2009 Independent |
Mr. Cunningham is a director of TETRA Technologies, Inc., a publicly traded energy services and chemicals company, and served as Chairman from December 2006 to May 2015. Mr. Cunningham also served as Chairman of Enterprise Products Holdings, LLC, the successor general partner of Enterprise Products Partners L.P., a publicly traded midstream energy limited partnership, from November 2010 to February 2013, and as a director from February 2013 to April 2014; and as a director of Agrium Inc., a publicly traded agricultural chemicals company from December 1996 to April 2013. | ||
Patrick D. Daniel (2,3,4) Calgary, Alberta, Canada |
2009 Independent |
Mr. Daniel is a director of Canadian Imperial Bank of Commerce; and Capital Power Corporation, a publicly traded North American power producer; and Chair of the North American Review Board of American Air Liquide Holdings, Inc., a subsidiary of a publicly traded industrial gases service company. Mr. Daniel served as a director of Enbridge Inc., a publicly traded energy delivery company from April 2000 to October 2012. During his tenure with Enbridge, he also served as President & Chief Executive Officer from January 2001 to February 2012 and as Chief Executive Officer from February 2012 to October 2012. He is a member of the Association of Professional Engineers and Geoscientists of Alberta. | ||
Ian W. Delaney (3,4,6) Toronto, Ontario, Canada |
2009 Independent |
Mr. Delaney is Chairman of The Westaim Corporation, a publicly traded investment company; and Ontario Air Ambulance Services Co. (Ornge) a not-for-profit medical air and ground transportation organization. Mr. Delaney served as a director of Sherritt International Corporation (Sherritt), a publicly traded diversified natural resource company that produces nickel, cobalt, thermal coal, oil and gas and electricity from October 1995 to May 2013. He also served as Chairman and Chief Executive Officer of Sherritt from January 2009 to December 2011 and Chairman of Sherritt from January 2012 to May 2013. Mr. Delaney also served as Chairman of UrtheCast Corp. (formerly Longford Energy Inc.), a publicly traded video technology development company, from August 2012 to October 2013 and as a director of Dacha Strategic Metals Inc., a publicly traded investment company focused on the acquisition, storage and trading of strategic metals from November 2012 to September 2014. | ||
Brian C. Ferguson (7) Calgary, Alberta, Canada |
2009 | Mr. Ferguson has been President & Chief Executive Officer of Cenovus since its formation on November 30, 2009. Mr. Ferguson is a Fellow of the Chartered Professional Accountants of Alberta and a member of the Chartered Professional Accountants of Canada. Mr. Ferguson has served as a director of The Toronto-Dominion Bank since April 2015. | ||
Michael A. Grandin (4,8) Calgary, Alberta, Canada |
2009 (Chair) Independent |
Mr. Grandin is the Chair of Cenovuss Board. He is also a director of BNS Split Corp. II, a publicly traded investment company; and HSBC Bank Canada. |
29 | ||
Cenovus Energy Inc. |
2015 Annual Information Form |
Name and Residence |
Director Since (1) |
Principal Occupation During the Past Five Years | ||
Steven F. Leer (2,4,5) Boca Grande, Florida, United States |
2015 Independent |
Mr. Leer is a lead director of Norfolk Southern Corporation, a publicly traded North American rail transportation provider; a lead director of USG Corporation (USG), a publicly traded manufacturer and distributor of high performance building systems; and a director of Parsons Corporation, a private engineering, construction, technical, and management services firm. Mr. Leer served as Chairman of Arch Coal, Inc. (Arch Coal), a publicly traded coal producing company, from April 2006 to April 2014, and served as a director of Arch Coal and its predecessor company from 1992. During his tenure with Arch Coal and its predecessor company, he also served as Chief Executive Officer from July 1992 to April 2012. | ||
Valerie A.A. Nielsen (2,4,5) Calgary, Alberta, Canada |
2009 Independent |
Ms. Nielsen was a director of Wajax Corporation, a publicly traded industrial parts and service company, from June 1995 to May 2012. | ||
Charles M. Rampacek (4,5,6) Dallas, Texas, United States |
2009 Independent |
Mr. Rampacek is a director of Flowserve Corporation, a publicly traded manufacturer of industrial equipment; and Energy Services Holdings, LLC, a private industrial services company that was formed in 2012 from the combination of Ardent Holdings, LLC and another company. Mr. Rampacek previously served as Chair of Ardent Holdings, LLC, from December 2008 to July 2012. Mr. Rampacek also served as a director of Enterprise Products Holdings, LLC, the sole general partner of Enterprise Products Partners, L.P., a publicly traded midstream energy limited partnership from November 2006 to September 2011; and Pilko & Associates L.P., a private chemical and energy advisory company from September 2011 to February 2014. | ||
Colin Taylor (2,3,4) Toronto, Ontario, Canada |
2009 Independent |
Mr. Taylor served two consecutive four-year terms as Chief Executive & Managing Partner of Deloitte LLP and then acted as Senior Counsel until his retirement in May 2008. Mr. Taylor is a Fellow of the Chartered Professional Accountants of Ontario and a member of the Chartered Professional Accountants of Canada. | ||
Wayne G. Thomson (4,5,6) Calgary, Alberta, Canada |
2009 Independent |
Mr. Thomson is a director of TVI Pacific Inc., a publicly traded international mining company; Chairman of Maha Energy Inc., a private North American oil and gas company; Chairman of Inventys Thermal Technologies Inc., a private carbon capture technology company; a director of Iskander Energy Corp., a private international oil and gas company; and Chairman and President of Enviro Valve Inc., a private company manufacturing proprietary pressure relief valves. Mr. Thomson served as Chief Executive Officer of Iskander Energy Corp. from November 2011 to August 2014. Mr. Thomson is a member of the Association of Professional Engineers and Geoscientists of Alberta.
|
(1) | Each of the directors first became members of Cenovuss Board pursuant to the Arrangement, with the exception of Mr. Leer who was elected as a director of Cenovuss Board at the April 29, 2015 Annual and Special Meeting of Shareholders. The term of each of the directors is from the date of the meeting at which he or she is elected or appointed until the next annual meeting of shareholders or until a successor is elected or appointed. |
(2) | Member of the Audit Committee. |
(3) | Member of the Human Resources and Compensation Committee. |
(4) | Member of the Nominating and Corporate Governance Committee. |
(5) | Member of the Reserves Committee. |
(6) | Member of the Safety, Environment and Responsibility Committee. |
(7) | As an officer and a non-independent director, Mr. Ferguson is not a member of any of the committees of Cenovuss Board. |
(8) | Ex-officio, by standing invitation, non-voting member of all other committees of Cenovuss Board. As an ex-officio non-voting member, Mr. Grandin attends as his schedule permits and may vote when necessary to achieve a quorum. |
30 | ||
Cenovus Energy Inc. |
2015 Annual Information Form |
EXECUTIVE OFFICERS
The following individuals served as executive officers of Cenovus as at December 31, 2015.
Name and Residence | Office Held and Principal Occupation During the Past Five Years | |
Brian C. Ferguson Calgary, Alberta, Canada |
President & Chief Executive Officer Mr. Fergusons biographical information is included under Directors. | |
Ivor M. Ruste Calgary, Alberta, Canada |
Executive Vice-President & Chief Financial Officer Mr. Ruste has been Executive Vice-President & Chief Financial Officer of Cenovus since its formation on November 30, 2009. | |
Harbir S. Chhina Calgary, Alberta, Canada |
Executive Vice-President, Oil Sands Development Mr. Chhina became Executive Vice-President, Oil Sands Development on September 1, 2015. From December 2010 to August 2015, Mr. Chhina was Cenovuss Executive Vice-President, Oil Sands. From November 2009 to November 2010, Mr. Chhina was Cenovuss Executive Vice-President, Enhanced Oil Development & New Resource Plays. | |
Judy A. Fairburn Calgary, Alberta, Canada |
Executive Vice-President, Business Innovation Ms. Fairburn became Executive Vice-President, Business Innovation on December 1, 2015. From February 2013 to November 2015, Ms. Fairburn was Cenovuss Executive Advisor. From November 2009 to January 2013, Ms. Fairburn was Cenovuss Executive Vice-President, Environment & Strategic Planning. | |
Jacqueline (Jacqui) A.T. McGillivray Calgary, Alberta, Canada |
Executive Vice-President, Safety & Organization Effectiveness Ms. McGillivray became Executive Vice-President, Safety & Organization Effectiveness on July 1, 2015. From October 2012 to June 2015, Ms. McGillivray was Cenovuss Senior Vice-President & Chief People Officer. From November 2010 to October 2012, Ms. McGillivray was Head of Global Human Resources at Talisman Energy Inc. | |
Robert W. Pease Calgary, Alberta, Canada |
Executive Vice-President, Corporate Strategy & President, Downstream Mr. Pease became Executive Vice-President, Corporate Strategy & President, Downstream on July 1, 2015. From June 2014 to June 2015, Mr. Pease was Cenovuss Executive Vice-President, Markets, Products & Transportation. From February 2014 to May 2014, Mr. Pease was Vice President, Global Business Excellence, Supply & Trading of Shell Trading (US) Company, a corporation that acts as the market interface for Royal Dutch Shell companies and affiliates in the U.S.; and from November 2008 until January 2014, he was President and Chief Executive Officer of Motiva Enterprises LLC, a refiner, distributer and marketer of fuels in the eastern and Gulf Coast regions of the U.S. | |
Alan C. Reid Calgary, Alberta, Canada |
Executive Vice-President, Environment, Corporate Affairs, Legal & General Counsel Mr. Reid became Executive Vice-President, Environment, Corporate Affairs, Legal & General Counsel on December 1, 2015. From September 2015 to November 2015, Mr. Reid was Cenovuss Executive Vice-President, Environment, Corporate Affairs & Legal. From January 2014 to August 2015, Mr. Reid was Cenovuss Senior Vice-President, Christina Lake & Narrows Lake. From January 2012 to January 2014, Mr. Reid was Cenovuss Senior Vice-President, Christina Lake. From November 2009 to January 2012, Mr. Reid was Cenovuss Vice-President, Regulatory, Health & Safety. | |
J. Drew Zieglgansberger Calgary, Alberta, Canada |
Executive Vice-President, Oil Sands Manufacturing Mr. Zieglgansberger became Executive Vice-President, Oil Sands Manufacturing on September 1, 2015. From June 2015 to August 2015, Mr. Zieglgansberger was Cenovuss Executive Vice-President, Operations Shared Services. From June 2012 to May 2015, Mr. Zieglgansberger was Cenovuss Senior Vice-President, Operations Shared Services. From January 2012 to May 2012, Mr. Zieglgansberger was Cenovuss Senior Vice-President, Regulatory, Local Community & Military. From December 2010 to January 2012, Mr. Zieglgansberger was Cenovuss Senior Vice-President, Christina Lake.
|
31 | ||
Cenovus Energy Inc. |
2015 Annual Information Form |
As of December 31, 2015, all of Cenovuss directors and executive officers, as a group, beneficially owned or exercised control or direction over, directly or indirectly, 1,055,623 common shares of Cenovus (Common Shares) or approximately 0.127 percent of the number of Common Shares that were outstanding as of such date.
Investors should be aware that some of Cenovuss directors and officers are directors and officers of other private and public companies. Some of these private and public companies may, from time to time, be involved in business transactions or banking relationships which may create situations in which conflicts might arise. Any such conflicts shall be resolved in accordance with the procedures and requirements of the relevant provisions of the CBCA, including the duty of such directors and officers to act honestly and in good faith with a view to the best interests of Cenovus.
CEASE TRADE ORDERS, BANKRUPTCIES, PENALTIES OR SANCTIONS
32 | ||
Cenovus Energy Inc. |
2015 Annual Information Form |
The Audit Committee mandate is included as Appendix C to this AIF.
COMPOSITION OF THE AUDIT COMMITTEE
33 | ||
Cenovus Energy Inc. |
2015 Annual Information Form |
External Auditor Service Fees
The following table provides information about the fees billed to Cenovus for professional services rendered by PricewaterhouseCoopers LLP in the years ended December 31, 2015 and 2014:
($ thousands) | 2015 | 2014 | ||||||
Audit Fees (1) |
2,692 | 2,597 | ||||||
Audit-Related Fees (2) |
482 | 202 | ||||||
Tax Fees (3) |
99 | 110 | ||||||
All Other Fees (4) |
- | 6 | ||||||
Total |
3,273 | 2,915 |
(1) | Audit Fees consist of the aggregate fees billed for the audit of the Corporations annual financial statements or services that are normally provided in connection with statutory and regulatory filings or engagements. |
(2) | Audit-Related Fees consist of the aggregate fees billed for assurance and related services that are reasonably related to the performance of the audit or review of the Corporations financial statements and are not reported as Audit Fees. The services provided in this category included audit-related services in relation to Cenovuss debt shelf prospectuses, systems development, controls testing and participation fees levied by the Canadian Public Accountability Board. |
(3) | Tax Fees consist of the aggregate fees billed for audit related fees, tax compliance, tax advice and tax planning. |
(4) | All Other Fees consist of subscriptions to auditor-provided and supported tools. |
34 | ||
Cenovus Energy Inc. |
2015 Annual Information Form |
DESCRIPTION OF CAPITAL STRUCTURE
The following is a summary of the rights, privileges, restrictions and conditions which are attached to Common Shares and Cenovuss first and second preferred shares (collectively the Preferred Shares). Cenovus is authorized to issue an unlimited number of Common Shares and First Preferred Shares and Second Preferred Shares not exceeding, in aggregate, 20 percent of the number of issued and outstanding Common Shares. As at December 31, 2015, there were approximately 833.3 million Common Shares and no Preferred Shares outstanding.
35 | ||
Cenovus Energy Inc. |
2015 Annual Information Form |
RATINGS
The following information relating to Cenovuss credit ratings is provided as it relates to the Corporations financing costs and liquidity. Specifically, credit ratings affect Cenovuss ability to obtain short-term and long-term financing and the cost of such financing. A reduction in the current rating on Cenovuss debt by the Corporations rating agencies or a negative change in its ratings outlook could adversely affect Cenovuss cost of financing and its access to sources of liquidity and capital. See Risk Factors in this AIF for further information.
The following table outlines the current ratings and outlooks of Cenovuss debt:
Standard & Poors Ratings Services (S&P) |
Moodys Investors Service (Moodys) |
DBRS Limited (DBRS) | ||||
Senior Unsecured Long-Term Rating |
BBB | Baa2 | BBB (high) | |||
Commercial Paper Short-Term Rating |
A-2 | P-2 | R-2 (high) | |||
Outlook/Trend |
Stable | Rating Under Review for downgrade |
Negative |
36 | ||
Cenovus Energy Inc. |
2015 Annual Information Form |
The declaration of dividends is at the sole discretion of Cenovuss Board and is considered each quarter. Effective the third quarter of 2015, Cenovus reduced the quarterly dividend by 40 percent from $0.2662 to $0.16 per common share. The Board has approved a first quarter dividend of $0.05 per share payable on March 31, 2016 to holders of Common Shares of record as of March 15, 2016. Readers should also refer to risk factors Risk Factors Financial Risks Ability to Pay Dividends for additional information.
Cenovus paid the following dividends over the last three years:
Dividends Paid | ||||||||||||||||||
($ per share) | Year | Q4 | Q3 | Q2 | Q1 | |||||||||||||
2015 |
0.8524 | 0.16 | 0.16 | 0.2662 | 0.2662 | |||||||||||||
2014 |
1.0648 | 0.2662 | 0.2662 | 0.2662 | 0.2662 | |||||||||||||
2013 |
0.968 | 0.242 | 0.242 | 0.242 | 0.242 |
All of the outstanding Common Shares are listed and posted for trading on the Toronto Stock Exchange (TSX) and the New York Stock Exchange (NYSE) under the symbol CVE. The following table outlines the share price trading range and volume of shares traded by month in 2015:
TSX | NYSE | |||||||||||||||||||||||||||||
Share Price Trading Range | Share Price Trading Range | |||||||||||||||||||||||||||||
High | Low | Close | Share Volume |
High | Low | Close | Share Volume | |||||||||||||||||||||||
($ per share) | (thousands) | (US$ per share) | (thousands) | |||||||||||||||||||||||||||
January |
24.95 | 21.87 | 24.09 | 86,649 | 20.89 | 17.37 | 18.89 | 49,901 | ||||||||||||||||||||||
February |
26.42 | 21.56 | 21.57 | 99,513 | 21.12 | 17.24 | 17.29 | 56,777 | ||||||||||||||||||||||
March |
22.48 | 20.45 | 21.34 | 101,794 | 17.93 | 16.29 | 16.88 | 47,505 | ||||||||||||||||||||||
April |
24.28 | 21.32 | 22.69 | 95,632 | 19.72 | 16.89 | 18.82 | 42,962 | ||||||||||||||||||||||
May |
23.25 | 20.23 | 20.52 | 77,995 | 19.28 | 16.20 | 16.49 | 38,034 | ||||||||||||||||||||||
June |
21.69 | 19.53 | 19.98 | 84,576 | 17.76 | 15.69 | 16.01 | 49,516 | ||||||||||||||||||||||
July |
20.07 | 16.98 | 19.06 | 86,880 | 15.97 | 13.04 | 14.58 | 50,471 | ||||||||||||||||||||||
August |
19.28 | 15.75 | 19.07 | 84,803 | 14.67 | 11.85 | 14.47 | 51,293 | ||||||||||||||||||||||
September |
20.91 | 17.00 | 20.24 | 135,093 | 15.80 | 12.76 | 15.16 | 74,684 | ||||||||||||||||||||||
October |
22.35 | 18.75 | 19.48 | 90,746 | 17.23 | 14.17 | 14.91 | 65,312 | ||||||||||||||||||||||
November |
21.81 | 19.10 | 19.81 | 65,882 | 16.68 | 14.32 | 14.80 | 39,867 | ||||||||||||||||||||||
December |
20.56 | 16.85 | 17.50 | 76,299 | 15.38 | 12.10 | 12.62 | 38,971 |
37 | ||
Cenovus Energy Inc. |
2015 Annual Information Form |
FINANCIAL RISKS
38 | ||
Cenovus Energy Inc. |
2015 Annual Information Form |
39 | ||
Cenovus Energy Inc. |
2015 Annual Information Form |
OPERATIONAL RISKS
40 | ||
Cenovus Energy Inc. |
2015 Annual Information Form |
41 | ||
Cenovus Energy Inc. |
2015 Annual Information Form |
42 | ||
Cenovus Energy Inc. |
2015 Annual Information Form |
ENVIRONMENTAL & REGULATORY RISKS
43 | ||
Cenovus Energy Inc. |
2015 Annual Information Form |
44 | ||
Cenovus Energy Inc. |
2015 Annual Information Form |
45 | ||
Cenovus Energy Inc. |
2015 Annual Information Form |
46 | ||
Cenovus Energy Inc. |
2015 Annual Information Form |
REPUTATION RISKS
OTHER RISK FACTORS
47 | ||
Cenovus Energy Inc. |
2015 Annual Information Form |
LEGAL PROCEEDINGS AND REGULATORY ACTIONS
During the year ended December 31, 2015, there were no legal proceedings to which Cenovus is or was a party, or that any of its property is or was the subject of, which involves a claim for damages in an amount, exclusive of interest and costs, that exceeds 10 percent of Cenovuss current assets and it is not aware of any such legal proceedings that are contemplated.
During the year ended December 31, 2015, there were no penalties or sanctions imposed against Cenovus by a court relating to provincial and territorial securities legislation or by a securities regulatory authority, nor have there been any other penalties or sanctions imposed by a court or regulatory body against the Corporation that would likely be considered important to a reasonable investor in making an investment decision, and it has not entered into any settlement agreements before a court relating to provincial and territorial securities legislation or with a securities regulatory authority.
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS
None of the Corporations directors or executive officers or any person or company that beneficially owns, or controls or directs, directly or indirectly, more than 10 percent of any class or series of Cenovuss outstanding voting securities, of which there are none that the Corporation is aware, or any associate or affiliate of any of the foregoing persons or companies, in each case, as at the date of this AIF, has or has had any material interest, direct or indirect, in any past transaction or any proposed transaction that has materially affected or is reasonably expected to materially affect Cenovus.
During the year ended December 31, 2015, Cenovus has not entered into any contracts, nor are there any contracts still in effect, that are material to the business, other than contracts entered into in the ordinary course of business, and each of the Arrangement Agreement and the Separation Agreement, as described under Risk Factors Other Risk Factors Arrangement Related Risk.
The Corporations independent auditors are PricewaterhouseCoopers LLP, Chartered Professional Accountants, who have issued an independent auditors report dated February 10, 2016 in respect of Cenovuss Consolidated Financial Statements which comprise the Consolidated Balance Sheets as at December 31, 2015 and December 31, 2014 and the Consolidated Statements of Earnings and Comprehensive Income, Shareholders Equity and Cash Flows for the years ended December 31, 2015, 2014, and 2013 and Cenovuss internal control over financial reporting as at December 31, 2015. PricewaterhouseCoopers LLP has advised that they are independent with respect to Cenovus within the meaning of the Code of Professional Conduct of the Chartered Professional Accountants of Alberta and the rules of the SEC.
Information relating to reserves in this AIF has been calculated by GLJ Petroleum Consultants Ltd. and McDaniel & Associates Consultants Ltd. as independent qualified reserves evaluators. The principals of each of GLJ Petroleum Consultants Ltd. and McDaniel & Associates Consultants Ltd., in each case, as a group own beneficially, directly or indirectly, less than one percent of any class of the Corporations securities.
TRANSFER AGENTS AND REGISTRARS
In Canada: |
In the United States: | |
Computershare Investor Services Inc. 8th Floor, 100 University Avenue Toronto, ON M5J 2Y1 Canada |
Computershare Trust Company NA 250 Royall St. Canton, MA 02021 U.S. |
Tel: 1-866-332-8898 Website: www.investorcentre.com/cenovus |
48 | ||
Cenovus Energy Inc. |
2015 Annual Information Form |
49 | ||
Cenovus Energy Inc. |
2015 Annual Information Form |
Oil and Natural Gas Liquids |
Natural Gas | |||||
bbl |
barrel |
Bcf |
billion cubic feet | |||
bbls/d |
barrels per day |
Mcf |
thousand cubic feet | |||
Mbbls/d |
thousand barrels per day |
MMcf |
million cubic feet | |||
MMbbls |
million barrels |
MMcf/d |
million cubic feet per day | |||
NGLs |
natural gas liquids |
MMBtu |
million British thermal units | |||
BOE |
barrel of oil equivalent |
CBM |
Coal Bed Methane | |||
BOE/d |
barrels of oil equivalent per day |
|||||
WTI |
West Texas Intermediate |
In this AIF, certain natural gas volumes have been converted to BOE on the basis of six Mcf to one bbl. BOE may be misleading, particularly if used in isolation. A conversion ratio of six Mcf to one bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent value equivalency at the wellhead.
TM denotes a trademark of Cenovus Energy Inc.
50 | ||
Cenovus Energy Inc. |
2015 Annual Information Form |
REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATORS
To the Board of Directors of Cenovus Energy Inc. (the Corporation):
1. | We have evaluated the Corporations reserves data as at December 31, 2015. The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2015, estimated using forecast prices and costs. |
2. | The reserves data are the responsibility of the Corporations management. Our responsibility is to express an opinion on the reserves data based on our evaluation. |
3. | We carried out our evaluation in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook as amended from time to time (the COGE Handbook) and maintained by the Society of Petroleum Evaluation Engineers (Calgary Chapter). |
4. | Those standards require that we plan and perform an evaluation to obtain reasonable assurance as to whether the reserves data are free of material misstatement. An evaluation also includes assessing whether the reserves data are in accordance with principles and definitions presented in the COGE Handbook. |
5. | The following table sets forth the estimated future net revenue (before deduction of income taxes) attributed to proved plus probable reserves, estimated using forecast prices and costs and calculated using a discount rate of 10 percent, included in the reserves data of the Corporation evaluated for the year ended December 31, 2015, and identifies the respective portions thereof that we have evaluated and reported on to the Corporations Board of Directors: |
Independent Qualified Reserves Evaluator |
Effective Date of Evaluation Report |
Location of Reserves |
Evaluated Net Present Value of Future Net (before income taxes, 10% discount rate) $ millions | |||||
| ||||||||
McDaniel & Associates Consultants Ltd. |
December 31, 2015 |
Canada | $20,280 | |||||
GLJ Petroleum Consultants Ltd. |
December 31, 2015 |
Canada | $1,286 | |||||
| ||||||||
$21,566 | ||||||||
|
6. | In our opinion, the reserves data respectively evaluated by us have, in all material respects, been determined and are in accordance with the COGE Handbook, consistently applied. |
7. | We have no responsibility to update our reports referred to in paragraph five for events and circumstances occurring after their respective effective dates. |
8. | Because the reserves data are based on judgments regarding future events, actual results will vary and the variations may be material. |
Executed as to our report referred to above:
/s/ P.A. Welch P.A. Welch, P. Eng. McDaniel & Associates Consultants Ltd. |
/s/ Keith M. Braaten Keith M. Braaten, P. Eng. GLJ Petroleum Consultants Ltd. | |
Calgary, Alberta, Canada | Calgary, Alberta, Canada |
February 9, 2016
A1 | ||
Cenovus Energy Inc. |
2015 Annual Information Form |
REPORT OF MANAGEMENT AND DIRECTORS
ON RESERVES DATA AND OTHER INFORMATION
Management and directors of Cenovus Energy Inc. (the Corporation) are responsible for the preparation and disclosure of information with respect to the Corporations oil and gas activities in accordance with securities regulatory requirements. This information includes reserves data.
Independent qualified reserves evaluators have evaluated the Corporations reserves data. A report from the independent qualified reserves evaluators will be filed with securities regulatory authorities concurrently with this report.
The Reserves Committee of the Board of Directors of the Corporation has:
(a) | reviewed the Corporations procedures for providing information to the independent qualified reserves evaluators; |
(b) | met with the independent qualified reserves evaluators to determine whether any restrictions affected the ability of the independent qualified reserves evaluators to report without reservation; and |
(c) | reviewed the reserves data with management and each of the independent qualified reserves evaluators. |
The Board of Directors of the Corporation has reviewed the Corporations procedures for assembling and reporting other information associated with oil and gas activities and has reviewed that information with management. The Board of Directors, on the recommendation of the Reserves Committee, has approved:
(a) | the content and filing with securities regulatory authorities of the reserves data and other oil and gas information; |
(b) | the filing of the report of the independent qualified reserves evaluators on the reserves data; and |
(c) | the content and filing of this report. |
Because the reserves data are based on judgments regarding future events, actual results will vary and the variations may be material.
/s/ Brian C. Ferguson Brian C. Ferguson |
/s/ Ivor M. Ruste Ivor M. Ruste | |
President & Chief Executive Officer | Executive Vice-President & | |
Chief Financial Officer | ||
/s/ Michael A. Grandin Michael A. Grandin |
/s/ Wayne G. Thomson Wayne G. Thomson | |
Director and Chair of the Board | Director and Chair of the Reserves Committee |
February 10, 2016
B1 | ||
Cenovus Energy Inc. |
2015 Annual Information Form |
AUDIT COMMITTEE MANDATE
I. | PURPOSE |
The Audit Committee (the Committee) is a committee of the Board of Directors (the Board) of Cenovus Energy Inc. (Cenovus or the Corporation) appointed to assist the Board in fulfilling its oversight responsibilities.
The Committees primary duties and responsibilities are to:
● | Oversee and monitor the effectiveness and integrity of the Corporations accounting and financial reporting processes, financial statements and system of internal controls regarding accounting and financial reporting compliance. |
● | Oversee audits of the Corporations financial statements. |
● | Review and evaluate the Corporations risk management framework and related processes including the supporting guidelines and practice documents. |
● | Review and approve managements identification of principal financial risks and monitor the process to manage such risks. |
● | Oversee and monitor the Corporations compliance with legal and regulatory requirements. |
● | Oversee and monitor the qualifications, independence and performance of the Corporations external auditors and internal auditing group. |
● | Provide an avenue of communication among the external auditors, management, the internal auditing group, and the Board. |
● | Report to the Board regularly. |
The Committee has the authority to conduct any review or investigation appropriate to fulfilling its responsibilities. The Committee shall have unrestricted access to personnel and information, and any resources necessary to carry out its responsibility. In this regard, the Committee may direct internal audit personnel to particular areas of examination.
II. | COMPOSITION AND MEETINGS |
Composition
The Committee shall consist of not less than three and not more than eight directors as determined by the Board, all of whom shall qualify as independent directors pursuant to National Instrument 52-110 Audit Committees (as implemented by the Canadian Securities Administrators (CSA) and as amended from time to time) (NI 52-110).
All members of the Committee shall be financially literate, as defined in NI 52-110, and at least one member shall have accounting or related financial managerial expertise. In particular, at least one member shall have, through (i) education and experience as a principal financial officer, principal accounting officer, controller, public accountant or auditor or experience in one or more positions that involve the performance of similar functions; (ii) experience actively supervising a principal financial officer, principal accounting officer, controller, public accountant, auditor or person performing similar functions; (iii) experience overseeing or assessing the performance of companies or public accountants with respect to the preparation, auditing or evaluation of financial statements; or (iv) other relevant experience:
● | An understanding of accounting principles and financial statements; |
● | The ability to assess the general application of such principles in connection with the accounting for estimates, accruals and reserves; |
● | Experience preparing, auditing, analyzing or evaluating financial statements that present a breadth and level of complexity of accounting issues that are generally comparable to the breadth and complexity of issues that can reasonably be expected to be raised by the Corporations financial statements, or experience actively supervising one or more persons engaged in such activities; |
● | An understanding of internal controls and procedures for financial reporting; and |
● | An understanding of audit committee functions. |
Committee members may not, other than in their respective capacities as members of the Committee, the Board or any other committee of the Board, accept directly or indirectly any consulting, advisory or other compensatory fee from the Corporation or any subsidiary of the Corporation, or be an affiliated person (as such term is defined in the United States Securities Exchange Act of 1934, as amended (the Exchange Act), and the rules, if any, adopted by the U.S. Securities and Exchange Commission (SEC) thereunder) of the Corporation or any subsidiary of the Corporation. For greater certainty, directors fees and fixed amounts of compensation under a retirement plan (including deferred compensation) for prior service with the Corporation that are not contingent on continued service should be the only compensation an Audit Committee member receives from the Corporation.
At least one member shall have experience in the oil and gas industry.
C1 | ||
Cenovus Energy Inc. |
2015 Annual Information Form |
Committee members shall not simultaneously serve on the audit committees of more than two other public companies, unless the Board first determines that such simultaneous service will not impair the ability of the relevant members to effectively serve on the Committee, and required public disclosure is made.
The non-executive Board Chair shall be a non-voting member of the Committee. See Quorum for further details.
Appointment of Committee Members
Committee members shall be appointed by the Board, effective after the election of directors at the annual meeting of shareholders, provided that any member may be removed or replaced at any time by the Board and shall, in any event, cease to be a member of the Committee upon ceasing to be a member of the Board.
Vacancies
Where a vacancy occurs at any time in the membership of the Committee, it may be filled by the Board.
Chair
The Nominating and Corporate Governance Committee will recommend for approval to the Board an unrelated Director to act as Chair of the Committee. The Board shall appoint the Chair of the Committee.
If unavailable or unable to attend a meeting of the Committee, the Chair shall ask another member to chair the meeting, failing which a member of the Committee present at the meeting shall be chosen to preside over the meeting by a majority of the members of the Committee present at such meeting.
The Chair presiding at any meeting of the Committee shall not have a casting vote.
The items pertaining to the Chair in this section should be read in conjunction with the Committee Chair section of the Chair of the Board of Directors and Committee Chair General Guidelines.
Secretary
The Committee shall appoint a Secretary who need not be a member of the Committee. The Secretary shall keep minutes of the meetings of the Committee.
Meetings
The Committee shall meet at least quarterly. The Chair of the Committee may call additional meetings as required. In addition, a meeting may be called by the non-executive Board Chair, the President & Chief Executive Officer, or any member of the Committee or by the external auditors.
Committee meetings may, by agreement of the Chair of the Committee, be held in person, by video conference, by means of telephone or by a combination of any of the foregoing.
Notice of Meeting
Notice of the time and place of each Committee meeting may be given orally, or in writing, or by facsimile, or by electronic means to each member of the Committee at least 24 hours prior to the time fixed for such meeting. Notice of each meeting shall also be given to the external auditors of the Corporation.
A member and the external auditors may, in any manner, waive notice of the Committee meeting. Attendance of a member at a meeting shall constitute waiver of notice of the meeting except where a member attends a meeting for the express purpose of objecting to the transaction of any business on the grounds that the meeting was not lawfully called.
Quorum
A majority of Committee members, present in person, by video conference, by telephone, or by a combination thereof, shall constitute a quorum. In addition, if an ex officio, non-voting members presence is required to attain a quorum of the Committee, then the said member shall be allowed to cast a vote at the meeting.
Attendance at Meetings
The President & Chief Executive Officer, the Executive Vice-President & Chief Financial Officer, the Comptroller and the head of internal audit are expected to be available to attend the Committees meetings or portions thereof.
The Committee may, by specific invitation, have other resource persons in attendance.
The Committee shall have the right to determine who shall, and who shall not, be present at any time during a meeting of the Committee.
Directors, who are not members of the Committee, may attend Committee meetings, on an ad hoc basis, upon prior consultation and approval by the Committee Chair or by a majority of the members of the Committee.
C2 | ||
Cenovus Energy Inc. |
2015 Annual Information Form |
Minutes
Minutes of each Committee meeting should be succinct yet comprehensive in describing substantive issues discussed by the Committee. However, they should clearly identify those items of responsibilities scheduled by the Committee for the meeting that have been discharged by the Committee and those items of responsibilities that are outstanding.
Minutes of Committee meetings shall be sent to all Committee members and to the external auditors. The full Board of Directors shall be kept informed of the Committees activities by a report following each Committee meeting.
III. | RESPONSIBILITIES |
Review Procedures
Review and update the Committees mandate annually, or sooner if the Committee deems it appropriate to do so. Review the summary of the Committees composition and responsibilities in the Corporations annual report, annual information form or other public disclosure documentation.
Review the summary of all approvals by the Committee of the provision of audit, audit-related, tax and other services by the external auditors for inclusion in the Corporations annual report and Annual Information Form filed with the CSA and the SEC.
Annual Financial Statements
1. | Discuss and review with management and the external auditors the Corporations and any subsidiary with public securities annual audited financial statements and related documents prior to their filing or distribution. Such review shall include: |
(a) | The annual financial statements and related notes including significant issues regarding accounting principles, practices and significant management estimates and judgments, including any significant changes in the Corporations selection or application of accounting principles, any major issues as to the adequacy of the Corporations internal controls and any special steps adopted in light of material control deficiencies. |
(b) | Managements Discussion and Analysis. |
(c) | The use of off-balance sheet financing including managements risk assessment and adequacy of disclosure. |
(d) | The external auditors audit examination of the financial statements and their report thereon. |
(e) | Any significant changes required in the external auditors audit plan. |
(f) | Any serious difficulties or disputes with management encountered during the course of the audit, including any restrictions on the scope of the external auditors work or access to required information. |
(g) | Other matters related to the conduct of the audit, which are to be communicated to the Committee under generally accepted auditing standards. |
2. | Review and formally recommend approval to the Board of the Corporations: |
(a) | Year-end audited financial statements. Such review shall include discussions with management and the external auditors as to: |
(i) | The accounting policies of the Corporation and any changes thereto. |
(ii) | The effect of significant judgments, accruals and estimates. |
(iii) | The manner of presentation of significant accounting items. |
(iv) | The consistency of disclosure. |
(b) | Managements Discussion and Analysis. |
(c) | Annual Information Form as to financial information. |
(d) | All prospectuses and information circulars as to financial information. |
The review shall include a report from the external auditors about the quality of the most critical accounting principles upon which the Corporations financial status depends, and which involve the most complex, subjective or significant judgmental decisions or assessments. |
Quarterly Financial Statements
3. | Review with management and the external auditors and either approve (such approval to include the authorization for public release) or formally recommend for approval to the Board the Corporations: |
(a) | Quarterly unaudited financial statements and related documents, including Managements Discussion and Analysis. |
(b) | Any significant changes to the Corporations accounting principles. |
Review quarterly unaudited financial statements prior to their distribution of any subsidiary of the Corporation with public securities. |
C3 | ||
Cenovus Energy Inc. |
2015 Annual Information Form |
Other Financial Filings and Public Documents
4. | Review and discuss with management financial information, including earnings press releases, the use of pro forma or non-GAAP financial information and earnings guidance, contained in any filings with the CSA or SEC or news releases related thereto, and consider whether the information is consistent with the information contained in the financial statements of the Corporation or any subsidiary with public securities. |
Internal Control Environment
5. | Receive and review from management, the external auditors and the internal auditors an annual report on the Corporations control environment as it pertains to the Corporations financial reporting process and controls. |
6. | Review and discuss significant financial risks or exposures and assess the steps management has taken to monitor, control, report and mitigate such risk to the Corporation. |
7. | Review in consultation with the internal auditors and the external auditors the degree of coordination in the audit plans of the internal auditors and the external auditors and enquire as to the extent the planned scope can be relied upon to detect weaknesses in internal controls, fraud, or other illegal acts. The Committee will assess the coordination of audit effort to assure completeness of coverage and the effective use of audit resources. Any significant recommendations made by the auditors for the strengthening of internal controls shall be reviewed and discussed with management. |
8. | Review with the President & Chief Executive Officer, the Executive Vice-President & Chief Financial Officer of the Corporation and the external auditors: (i) all significant deficiencies and material weaknesses in the design or operation of the Corporations internal controls and procedures for financial reporting which could adversely affect the Corporations ability to record, process, summarize and report financial information required to be disclosed by the Corporation in the reports that it files or submits under the Exchange Act or applicable Canadian federal and provincial legislation and regulations within the required time periods, and (ii) any fraud, whether or not material, that involves management of the Corporation or other employees who have a significant role in the Corporations internal controls and procedures for financial reporting. |
9. | Review significant findings prepared by the external auditors and the internal auditing department together with managements responses. |
Risk Oversight
10. | Review and evaluate the Corporations risk management framework and related processes including the supporting guidelines and practice documents. |
Other Review Items
11. | Review policies and procedures with respect to officers and directors expense accounts and perquisites, including their use of corporate assets, and consider the results of any review of these areas by the internal auditor or the external auditors. |
12. | Review all related party transactions between the Corporation and any executive officers or directors, including affiliations of any executive officers or directors. |
13. | Review with the General Counsel, the head of internal audit and the external auditors the results of their review of the Corporations monitoring compliance with each of the Corporations published codes of business conduct and applicable legal requirements. |
14. | Review legal and regulatory matters, including correspondence with and reports received from regulators and government agencies, that may have a material impact on the interim or annual financial statements and related corporate compliance policies and programs. Members from the Legal and Tax groups should be at the meeting in person to deliver their respective reports. |
15. | Review policies and practices with respect to off-balance sheet transactions and trading and hedging activities, and consider the results of any review of these areas by the internal auditors or the external auditors. |
16. | Ensure that the Corporations presentation of hydrocarbon reserves has been reviewed with the Reserves Committee of the Board. |
17. | Review managements processes in place to prevent and detect fraud. |
18. | Review: |
(a) | procedures for the receipt, retention and treatment of complaints received by the Corporation, including confidential, anonymous submissions by employees of the Corporation, regarding accounting, internal accounting controls, or auditing matters; and |
C4 | ||
Cenovus Energy Inc. |
2015 Annual Information Form |
(b) | a summary of any significant investigations regarding such matters. |
19. | Meet on a periodic basis separately with management. |
External Auditors
20. | Be directly responsible, in the Committees capacity as a committee of the Board and subject to the rights of shareholders and applicable law, for the appointment, compensation, retention and oversight of the work of the external auditors (including resolution of disagreements between management and the external auditors regarding financial reporting) for the purpose of preparing or issuing an audit report, or performing other audit, review or attest services for the Corporation. The external auditors shall report directly to the Committee. |
21. | Meet on a regular basis with the external auditors (without management present) and have the external auditors be available to attend Committee meetings or portions thereof at the request of the Chair of the Committee or by a majority of the members of the Committee. |
22. | Review and discuss a report from the external auditors at least quarterly regarding: |
(a) | All critical accounting policies and practices to be used; |
(b) | All alternative treatments within accounting principles for policies and practices related to material items that have been discussed with management, including the ramifications of the use of such alternative disclosures and treatments, and the treatment preferred by the external auditors; and |
(c) | Other material written communications between the external auditors and management, such as any management letter or schedule of unadjusted differences. |
23. | Obtain and review a report from the external auditors at least annually regarding: |
(a) | The external auditors internal quality-control procedures. |
(b) | Any material issues raised by the most recent internal quality-control review, or peer review, of the external auditors, or by any inquiry or investigation by governmental or professional authorities, within the preceding five years, respecting one or more independent audits carried out by the external auditors, and any steps taken to deal with those issues. |
(c) | To the extent contemplated in the following paragraph, all relationships between the external auditors and the Corporation. |
24. | Review and discuss at least annually with the external auditors all relationships that the external auditors and their affiliates have with the Corporation and its affiliates in order to determine the external auditors independence, including, without limitation, (i) receiving and reviewing, as part of the report described in the preceding paragraph, a formal written statement from the external auditors delineating all relationships that may reasonably be thought to bear on the independence of the external auditors with respect to the Corporation and its affiliates, (ii) discussing with the external auditors any disclosed relationships or services that the external auditors believe may affect the objectivity and independence of the external auditors, and (iii) recommending that the Board take appropriate action in response to the external auditors report to satisfy itself of the external auditors independence. |
25. | Review and evaluate annually: |
(a) | The external auditors and the lead partner of the external auditors teams performance, and make a recommendation to the Board of Directors regarding the reappointment of the external auditors at the annual meeting of the Corporations shareholders or regarding the discharge of such external auditors. |
(b) | The terms of engagement of the external auditors together with their proposed fees. |
(c) | External audit plans and results. |
(d) | Any other related audit engagement matters. |
(e) | The engagement of the external auditors to perform non-audit services, together with the fees therefor, and the impact thereof, on the independence of the external auditors. |
(f) | Review the Annual Report of the Canadian Public Accountability Board (CPAB) concerning audit quality in Canada and discuss implications for Cenovus. |
(g) | Review any reports issued by CPAB regarding the audit of Cenovus. |
26. | Conduct periodically a comprehensive review of the external auditor, with the outcome intended to assist the Committee to identify potential areas for improvement for the audit firm, and to reach a final conclusion on whether the auditor should be reappointed or the audit put out for tender. |
27. | Upon reviewing and discussing the information provided to the Committee in accordance with paragraphs 22 through 25, evaluate the external auditors qualifications, performance and independence, including whether or not the external auditors quality controls are adequate and the provision of permitted non-audit services is compatible with maintaining auditor independence, taking into account the opinions of management and the head of internal audit. The Committee shall present to the Board its conclusions in this respect. |
C5 | ||
Cenovus Energy Inc. |
2015 Annual Information Form |
28. | Review the rotation of partners on the audit engagement team in accordance with applicable law. Consider whether, in order to assure continuing external auditor independence, it is appropriate to adopt a policy of rotating the external auditing firm on a regular basis. |
29. | Set clear hiring policies for the Corporations hiring of employees or former employees of the external auditors. |
30. | Consider with management and the external auditors the rationale for employing audit firms other than the principal external auditors. |
31. | Consider and review with the external auditors, management and the head of internal audit: |
(a) | Significant findings during the year and managements responses and follow-up thereto. |
(b) | Any difficulties encountered in the course of their audits, including any restrictions on the scope of their work or access to required information, and managements response. |
(c) | Any significant disagreements between the external auditors or internal auditors and management. |
(d) | Any changes required in the planned scope of their audit plan. |
(e) | The resources, budget, reporting relationships, responsibilities and planned activities of the internal auditors. |
(f) | The internal audit department mandate. |
(g) | Internal audits compliance with the Institute of Internal Auditors standards. |
Internal Audit Group and Independence
32. | Meet on a periodic basis separately with the head of internal audit. |
33. | Review and concur in the appointment, compensation, replacement, reassignment, or dismissal of the head of internal audit. |
34. | Confirm and assure, annually, the independence of the internal audit group and the external auditors. |
Approval of Audit and Non-Audit Services
35. | Review and, where appropriate, approve the provision of all permitted non-audit services (including the fees and terms thereof) in advance of the provision of those services by the external auditors (subject to the de minimus exception for non-audit services described in the Exchange Act or applicable CSA and SEC legislation and regulations, which services are approved by the Committee prior to the completion of the audit). |
36. | Review and, where appropriate and permitted, approve the provision of all audit services (including the fees and terms thereof) in advance of the provision of those services by the external auditors. |
37. | If the pre-approvals contemplated in paragraphs 34 and 35 are not obtained, approve, where appropriate and permitted, the provision of all audit and non-audit services promptly after the Committee or a member of the Committee to whom authority is delegated becomes aware of the provision of those services. |
38. | Delegate, if the Committee deems necessary or desirable, to subcommittees consisting of one or more members of the Committee, the authority to grant the pre-approvals and approvals described in paragraphs 34 through 36. The decision of any such subcommittee to grant pre-approval shall be presented to the full Committee at the next scheduled Committee meeting. |
39. | Establish policies and procedures for the pre-approvals described in paragraphs 34 and 35 so long as such policies and procedures are detailed as to the particular service, the Committee is informed of each service and such policies and procedures do not include delegation to management of the Committees responsibilities under the Exchange Act or applicable CSA and SEC legislation and regulations. |
Other Matters
40. | Review and concur in the appointment, replacement, reassignment, or dismissal of the Chief Financial Officer. |
41. | Upon a majority vote of the Committee outside resources may be engaged where and if deemed advisable. |
42. | Report Committee actions to the Board of Directors with such recommendations as the Committee may deem appropriate. |
43. | Conduct or authorize investigations into any matters within the Committees scope of responsibilities. The Committee shall be empowered to retain, obtain advice or otherwise receive assistance from independent counsel, accountants, or others to assist it in the conduct of any investigation as it deems necessary and the carrying out of its duties. |
C6 | ||
Cenovus Energy Inc. |
2015 Annual Information Form |
44. | Determine the appropriate funding for payment by the Corporation (i) of compensation to the external auditors for the purpose of preparing or issuing an audit report or performing other audit, review or attest services for the Corporation, (ii) of compensation to any advisors employed by the Committee, and (iii) of ordinary administrative expenses of the Committee that are necessary or appropriate in carrying out its duties. |
45. | Obtain assurance from the external auditors that no disclosure to the Committee is required pursuant to the provisions of the Exchange Act regarding the discovery of illegal acts by the external auditors. |
46. | Review and reassess the adequacy of this Mandate annually and recommend any proposed changes to the Board for approval. |
47. | Consider for implementation any recommendations of the Nominating and Corporate Governance Committee of the Board with respect to the Committees effectiveness, structure, processes or mandate. |
48. | Perform such other functions as required by law, the Corporations by-laws or the Board of Directors. |
49. | Consider any other matters referred to it by the Board of Directors. |
C7 | ||
Cenovus Energy Inc. |
2015 Annual Information Form |
MANAGEMENTS DISCUSSION AND ANALYSIS
FOR THE YEAR ENDED DECEMBER 31, 2015
WHERE TO FIND: |
||||
2 | ||||
4 | ||||
5 | ||||
6 | ||||
8 | ||||
13 | ||||
13 | ||||
18 | ||||
22 | ||||
24 | ||||
26 | ||||
28 | ||||
29 | ||||
33 | ||||
CRITICAL ACCOUNTING JUDGMENTS, ESTIMATES AND ACCOUNTING POLICIES |
38 | |||
40 | ||||
41 | ||||
41 | ||||
43 | ||||
45 |
This Managements Discussion and Analysis (MD&A) for Cenovus Energy Inc. (we, our, us, its, Cenovus, or the Company) dated February 10, 2016, should be read in conjunction with our December 31, 2015 audited Consolidated Financial Statements and accompanying notes (Consolidated Financial Statements). All of the information and statements contained in this MD&A are made as of February 10, 2016, unless otherwise indicated. This MD&A contains forward-looking information about our current expectations, estimates, projections and assumptions. See the Advisory for information on the risk factors that could cause actual results to differ materially and the assumptions underlying our forward-looking information. Cenovus Management prepared the MD&A. The Audit Committee of the Cenovus Board of Directors (the Board) reviewed and recommended the MD&A for approval by the Board, which occurred on February 10, 2016. Additional information about Cenovus, including our quarterly and annual reports, the Annual Information Form (AIF) and Form 40-F, is available on SEDAR at sedar.com, EDGAR at sec.gov and on our website at cenovus.com. Information on or connected to our website, even if referred to in this MD&A, does not constitute part of this MD&A.
Basis of Presentation
This MD&A and the Consolidated Financial Statements and comparative information have been prepared in Canadian dollars, except where another currency has been indicated, and in accordance with International Financial Reporting Standards (IFRS or GAAP) as issued by the International Accounting Standards Board (IASB). Production volumes are presented on a before royalties basis.
Non-GAAP Measures
Certain financial measures in this document do not have a standardized meaning as prescribed by IFRS, such as Operating Cash Flow, Cash Flow, Operating Earnings, Free Cash Flow, Debt, Net Debt, Capitalization and Adjusted Earnings before Interest, Taxes, Depreciation and Amortization (Adjusted EBITDA) and therefore are considered non-GAAP measures. These measures may not be comparable to similar measures presented by other issuers. These measures have been described and presented in order to provide shareholders and potential investors with additional measures for analyzing our ability to generate funds to finance our operations and information regarding our liquidity. This additional information should not be considered in isolation or as a substitute for measures prepared in accordance with IFRS. The definition and reconciliation of each non-GAAP measure is presented in the Financial Results or Liquidity and Capital Resources sections of this MD&A.
Cenovus Energy Inc. | 1 | 2015 Managements Discussion and Analysis |
We are a Canadian integrated oil company headquartered in Calgary, Alberta, with our shares listed on the Toronto and New York stock exchanges. On December 31, 2015, we had a market capitalization of approximately $15 billion. We are in the business of developing, producing and marketing crude oil, natural gas liquids (NGLs) and natural gas in Canada with marketing activities and refining operations in the United States (U.S.). Our average crude oil and NGLs (collectively, crude oil) production in 2015 was approximately 207,000 barrels per day and our average natural gas production was 441 MMcf per day. Our refineries processed an average of 419,000 gross barrels per day of crude oil feedstock into an average of 444,000 gross barrels per day of refined products.
Our Key Message for 2015
2015 was a challenging year for the oil and gas industry as the low commodity price environment prompted significant reductions in capital spending programs and extensive efforts to reduce costs. The deterioration of crude oil prices resulted in a significant decline in our cash flow and earnings.
During these volatile times, Cenovus has remained focused on delivering value through preserving financial resilience, achieving sustainable cost reductions and exercising capital discipline. Together, our common share issuance and the sale of our royalty interest and mineral fee title lands business raised cash proceeds of approximately $4.7 billion. These transactions significantly strengthened our balance sheet and our net debt to capitalization ratio was 16 percent at December 31, 2015. We also reduced our capital, operating and general and administrative spending, capturing savings of approximately $540 million, relative to our budget.
We expect commodity prices to remain low for the foreseeable future and continue to make adjustments to our capital spending and cost structure. For more information, we direct our readers to review the news release for our revised 2016 guidance dated February 11, 2016. The news release is available on our website at cenovus.com, on SEDAR at sedar.com and on EDGAR at sec.gov.
Our Strategy
Our strategy is to create value by developing our vast oil sands resources and by achieving stronger global prices for our products. It is based on our disciplined execution, focused innovation and our financial strength. The manufacturing approach we use to produce crude oil is a key factor in how we execute our strategy. Applying standardized and repeatable designs and processes to the construction and operation of our facilities provides us with opportunities to reduce costs, and improve productivity and efficiencies at every phase of our oil sands projects. We are focused on driving total shareholder returns.
Our integrated approach positions us to capture the full value chain from production to high-quality end products like transportation fuels. It relies on:
| Our producing asset mix, including: |
¡ | Oil sands for long-term growth; |
¡ | Conventional crude oil for near-term cash flow and diversification of our revenue stream; and |
¡ | Natural gas for the fuel we use at our oil sands and refining facilities, and for the cash flow it provides to help fund our capital spending programs. |
| Our marketing, products and transportation activities, including: |
¡ | Refining oil into various products to reduce the impact of commodity price fluctuations; |
¡ | Creating a variety of oil blends to help maximize our transportation and refining options; and |
¡ | Accessing new markets that will position us to achieve the best pricing for our oil. |
We have adopted a more moderate and staged approach to future oil sands expansions. We will consider expanding existing projects and developing emerging projects only when we believe we will maximize cost savings and capital efficiencies.
Oil Development
We are focusing on the development of our substantial crude oil resources, predominantly from Foster Creek and Christina Lake. Our future opportunities are currently based on the development of the land positions that we hold in the oil sands in northern Alberta, including Narrows Lake, Telephone Lake and Grand Rapids, as well as our conventional oil opportunities.
We are positioned to increase our annual net crude oil production, including our conventional crude oil operations, by fully developing our production projects and those that currently have regulatory approval.
Disciplined Manufacturing
We apply a manufacturing-like, phased approach to developing our oil sands assets. This approach incorporates learnings from previous phases into future growth plans, positioning us to minimize costs. We continue to focus on executing our business plan in a safe, predictable and reliable way, leveraging the strong foundation we have built to date. We are committed to developing our resources safely and responsibly.
Cenovus Energy Inc. | 2 | 2015 Managements Discussion and Analysis |
Financial Strength
Maintaining a strong balance sheet is necessary to execute our strategy. We anticipate our total annual capital investment for 2016 to be between $1.2 billion and $1.3 billion. This is 27 percent lower than in 2015, reflecting moderate spending in response to the sustained low commodity price environment. At December 31, 2015, we had $4.1 billion of cash on hand, $4.0 billion of undrawn capacity on our committed credit facility, and no debt maturing until the fourth quarter of 2019. To help ensure our continued financial flexibility, we will pursue further cost reductions, manage our asset portfolio and consider other corporate and financial opportunities that may be available to us.
Dividend
In 2015, we paid a dividend of $0.8524 per share compared with $1.0648 per share in 2014 (2013 $0.968 per share). We reduced our dividend by 40 percent in the third quarter of 2015, from $0.2662 per share to $0.16 per share, as part of our strategy to maintain our long-term financial resilience. Our dividend was further reduced to $0.05 per share in the first quarter of 2016. The declaration of dividends is at the sole discretion of our Board and is considered each quarter.
Focused Innovation
Technology development, research activities and understanding our impact on the environment play increasingly larger roles in all aspects of our business. We continue to seek out new technologies and are actively developing technologies with a focus on increasing recoveries from our reservoirs, and improving cycle times, margins and environmental performance. We have a track record of developing innovative solutions that unlock challenging crude oil resources, building on our history of excellent project execution. Environmental considerations are embedded into our business approach with the objective of reducing our environmental impact.
Our Operations
Oil Sands
Our operations include the following steam-assisted gravity drainage (SAGD) oil sands projects in northern Alberta:
2015 | ||||||||||||||||
Ownership Interest (percent) |
Net Production Volumes (bbls/d) |
Gross Production Volumes (bbls/d) |
||||||||||||||
Existing Projects |
||||||||||||||||
Foster Creek |
50 | 65,345 | 130,690 | |||||||||||||
Christina Lake |
50 | 74,975 | 149,950 | |||||||||||||
Narrows Lake |
50 | - | - | |||||||||||||
Emerging Projects |
||||||||||||||||
Telephone Lake |
100 | - | - | |||||||||||||
Grand Rapids |
100 | - | - |
Foster Creek, Christina Lake and Narrows Lake are operated by Cenovus and jointly owned with ConocoPhillips, an unrelated U.S. public company. Foster Creek and Christina Lake are producing and Narrows Lake is in the initial stages of development. These projects are located in the Athabasca region of northeastern Alberta. Two of our 100 percent-owned emerging projects are Telephone Lake and Grand Rapids, located within the Borealis and Greater Pelican Lake regions of northeastern Alberta, respectively.
2015 | ||||||||||
($ millions) | Crude Oil | Natural Gas | ||||||||
Operating Cash Flow |
1,046 | 10 | ||||||||
Capital Investment |
1,184 | 1 | ||||||||
Operating Cash Flow Net of Related Capital Investment |
(138 | ) | 9 |
Conventional
Crude oil production from our Conventional business segment continues to generate dependable near-term cash flows. This production provides diversification to our revenue stream and enables further development of our oil sands assets. Our natural gas production acts as an economic hedge for the natural gas required as a fuel source at both our oil sands and refining operations and provides cash flow to help fund our growth opportunities.
2015 | ||||||||||
($ millions) | Crude Oil (1) | Natural Gas | ||||||||
Operating Cash Flow |
683 | 297 | ||||||||
Capital Investment |
231 | 13 | ||||||||
Operating Cash Flow Net of Related Capital Investment |
452 | 284 |
(1) | Includes NGLs. |
Cenovus Energy Inc. | 3 | 2015 Managements Discussion and Analysis |
We have established crude oil and natural gas producing assets, including heavy oil assets at Pelican Lake, a carbon dioxide (CO2) enhanced oil recovery project in Weyburn, Saskatchewan, and emerging tight oil assets in Alberta.
Refining and Marketing
Our operations include two refineries located in Illinois and Texas that are jointly owned with and operated by Phillips 66, an unrelated U.S. public company.
2015 | ||||||||||
Ownership Interest (percent) |
Gross Nameplate Capacity (Mbbls/d) |
|||||||||
Wood River |
50 | 314 | ||||||||
Borger |
50 | 146 |
Our refining operations allow us to capture the value from crude oil production through to refined products, such as diesel, gasoline and jet fuel, to partially mitigate volatility associated with regional North American crude oil price differential fluctuations. This segment also includes our crude-by-rail terminal operations, located in Bruderheim, Alberta, and the marketing of third-party purchases and sales of product undertaken to provide operational flexibility for transportation commitments, product quality, delivery points and customer diversification.
($ millions) | 2015 | |||
Operating Cash Flow |
385 | |||
Capital Investment |
248 | |||
Operating Cash Flow Net of Related Capital Investment |
137 |
In 2015, Cenovus delivered on the commitments we made to our shareholders. We met our production targets, achieved significant sustainable cost savings in all areas of our business and strengthened our balance sheet. However, our financial results continued to be significantly impacted by low crude oil prices. Average crude oil benchmark prices declined approximately 50 percent from 2014. The expectation of sustained low commodity prices resulted in asset impairments of $338 million, further decreasing our earnings.
During 2015, Cenovus remained focused on delivering value through preserving financial resilience, achieving sustainable cost reductions and exercising capital discipline. We captured savings of approximately $540 million, relative to our budget, by reducing our capital, operating, and general and administrative spending. Approximately 50 percent of these savings came from lower than budgeted operating costs and 40 percent from reduced capital expenditures, including supply chain management initiatives.
In 2015, we also:
| Issued 67.5 million common shares at $22.25 per share for net proceeds of $1.4 billion; |
| Completed the sale of our royalty interest and mineral fee title lands business for cash proceeds of approximately $3.3 billion; |
| Renegotiated our $3.0 billion committed credit facility, extending the maturity date to November 30, 2019 and added a new $1.0 billion tranche under the same facility with a maturity date of November 30, 2017; |
| Reduced capital investment by 44 percent or $1.3 billion, compared with 2014; |
| Realized gains of $656 million from crude oil and natural gas risk management activities; |
| Reduced our workforce by 24 percent to align with our more moderate approach to oil sands expansions; |
| Decreased our total crude oil operating costs by 20 percent or $228 million, compared with 2014; |
| Increased proved bitumen reserves by 11 percent primarily due to approval of an area expansion at Christina Lake; |
| Closed the purchase of a crude-by-rail terminal for $75 million, plus adjustments, to expand our portfolio of transportation options; |
| Received regulatory approval for Christina Lake phase H, a 50,000 gross barrels per day phase; and |
| Reduced our annual dividend from $1.0648 per share to $0.8524 per share. |
Cenovus Energy Inc. | 4 | 2015 Managements Discussion and Analysis |
Our upstream assets continued to perform well in 2015. Total crude oil production averaged 206,947 barrels per day during the year.
Crude Oil Production Volumes
(barrels per day) | 2015 | Percent Change |
2014 | Percent Change |
2013 | |||||||||||||||||||||||
Oil Sands |
||||||||||||||||||||||||||||
Foster Creek |
65,345 | 10% | 59,172 | 11% | 53,190 | |||||||||||||||||||||||
Christina Lake |
74,975 | 9% | 69,023 | 40% | 49,310 | |||||||||||||||||||||||
140,320 | 9% | 128,195 | 25% | 102,500 | ||||||||||||||||||||||||
Conventional |
||||||||||||||||||||||||||||
Heavy Oil |
34,888 | (12)% | 39,546 | (2)% | 40,245 | |||||||||||||||||||||||
Light and Medium Oil |
30,486 | (12)% | 34,531 | (3)% | 35,467 | |||||||||||||||||||||||
NGLs (1) |
1,253 | 3% | 1,221 | 15% | 1,063 | |||||||||||||||||||||||
66,627 | (12)% | 75,298 | (2)% | 76,775 | ||||||||||||||||||||||||
Total Crude Oil Production |
206,947 | 2% | 203,493 | 14% | 179,275 |
(1) | NGLs include condensate volumes. |
Foster Creek production increased in 2015 due to the ramp-up of production from phase F and production from additional wells, partially offset by the impact of a forest fire in the second quarter, which decreased full-year production by approximately 2,600 barrels per day. Fourth quarter production was lower compared with 2014. Improved wellbore conformance accelerated production from more mature wells, resulting in faster declines from these wells. To preserve capital, we chose in 2015 to defer some planned well pads, which combined with the faster declines, contributed to lower fourth quarter volumes. In addition, while well downtime at Foster Creek was within expected ranges for 2015, a higher than average number of wells were down for servicing in the second half of the year, which further impacted production.
Production from Christina Lake increased compared with 2014 due to production from additional wells and improved performance of our facilities.
In 2015, our Conventional crude oil production decreased from 2014. An increase in production from successful horizontal well performance in southern Alberta was more than offset by expected natural declines, the divestiture of non-core assets in 2014, and the sale of our royalty interest and mineral fee title lands business. Production also declined due to reduced capital investment. Divested assets contributed 2,555 barrels per day (2014 6,532 barrels per day) to annual production.
Natural Gas Production Volumes
(MMcf per day) | 2015 | 2014 | 2013 | |||||||||||||
Conventional |
422 | 466 | 508 | |||||||||||||
Oil Sands |
19 | 22 | 21 | |||||||||||||
441 | 488 | 529 |
Our natural gas production declined 10 percent in 2015. Production decreased primarily due to expected natural declines and the sale of our royalty interest and mineral fee title lands business, which produced 10 MMcf per day during the year (2014 20 MMcf per day).
Oil and Gas Reserves
Our proved bitumen reserves increased 11 percent to approximately 2.2 billion barrels and our proved plus probable bitumen reserves remained at approximately at 3.3 billion barrels. Additional information about our reserves and resources is included in the Oil and Gas Reserves and Resources section of this MD&A.
Operating Netbacks
Crude Oil (1) ($/bbl) | Natural Gas ($/Mcf) | |||||||||||||||||||||||||||||||||||
2015 | 2014 | 2013 | 2015 | 2014 | 2013 | |||||||||||||||||||||||||||||||
Price (2) |
35.38 | 71.35 | 67.01 | 2.92 | 4.37 | 3.20 | ||||||||||||||||||||||||||||||
Royalties |
1.75 | 6.18 | 5.01 | 0.07 | 0.08 | 0.04 | ||||||||||||||||||||||||||||||
Transportation and Blending (2) (3) |
5.48 | 2.98 | 3.12 | 0.11 | 0.12 | 0.11 | ||||||||||||||||||||||||||||||
Operating Expenses (4) |
11.98 | 15.40 | 15.49 | 1.20 | 1.22 | 1.16 | ||||||||||||||||||||||||||||||
Production and Mineral Taxes |
0.22 | 0.50 | 0.48 | 0.01 | 0.05 | 0.02 | ||||||||||||||||||||||||||||||
Netback Excluding Realized Risk Management |
15.95 | 46.29 | 42.91 | 1.53 | 2.90 | 1.87 | ||||||||||||||||||||||||||||||
Realized Risk Management Gain (Loss) |
7.51 | 0.50 | 1.09 | 0.37 | 0.04 | 0.32 | ||||||||||||||||||||||||||||||
Netback Including Realized Risk Management |
23.46 | 46.79 | 44.00 | 1.90 | 2.94 | 2.19 |
(1) | Includes NGLs. |
(2) | The crude oil price and transportation and blending costs exclude the cost of purchased condensate which is blended with the heavy oil. On a per-barrel of unblended crude oil basis, the cost of condensate was $21.09 per barrel (2014 $30.49 per barrel; 2013 $28.33 per barrel). |
(3) | The netbacks do not reflect non-cash write-downs of product inventory. There was no product inventory write-down recorded in 2013. See the Oil Sands and Conventional Reportable Segments sections of this MD&A for more details. |
(4) | For all periods presented, we reclassified employee long-term incentive costs from operating expenses to general and administrative costs. |
Cenovus Energy Inc. | 5 | 2015 Managements Discussion and Analysis |
Our average crude oil netback in 2015, excluding realized risk management gains and losses, decreased significantly compared with 2014. Lower sales prices, consistent with the decline in benchmark prices, were partially offset by weakening of the Canadian dollar relative to the U.S. dollar and a decline in royalties and operating costs. The weakening of the Canadian dollar compared with 2014 had a positive impact on our crude oil price of approximately $4.81 per barrel.
In 2015, our average natural gas netback, excluding realized risk management gains and losses, decreased primarily due to lower sales prices, consistent with the decline in the AECO benchmark price.
Refining
In 2015, we successfully completed planned turnarounds at both of our Borger and Wood River refineries and received permit approval for the Wood River debottlenecking project.
2015 | Percent Change |
2014 | Percent Change |
2013 | ||||||||||||||||||
Crude Oil Runs (1) (Mbbls/d) |
419 | (1)% | 423 | (4)% | 442 | |||||||||||||||||
Heavy Crude Oil (1) |
200 | 1% | 199 | (10)% | 222 | |||||||||||||||||
Refined Product (1) (Mbbls/d) |
444 | - | 445 | (4)% | 463 | |||||||||||||||||
Crude Utilization (1) (percent) |
91 | (1)% | 92 | (5)% | 97 |
(1) | Represents 100 percent of the Wood River and Borger refinery operations. |
Further information on the changes in our production volumes, items included in our operating netbacks and refining results can be found in the Reportable Segments section of this MD&A. Further information on our risk management activities can be found in the Risk Management section of this MD&A and in the notes to the Consolidated Financial Statements.
COMMODITY PRICES UNDERLYING OUR FINANCIAL RESULTS
Key performance drivers for our financial results include commodity prices, price differentials, refining crack spreads as well as the U.S./Canadian dollar exchange rate. The following table shows selected market benchmark prices and the U.S./Canadian dollar average exchange rates to assist in understanding our financial results.
Selected Benchmark Prices and Exchange Rates (1)
Q4 2015 |
Percent Change |
Q4 2014 |
2015 | 2014 | 2013 | |||||||||||||||||||||
Crude Oil Prices (US$/bbl) |
||||||||||||||||||||||||||
Brent |
||||||||||||||||||||||||||
Average |
44.71 | (42)% | 76.98 | 53.64 | 99.51 | 108.76 | ||||||||||||||||||||
End of Period |
37.28 | (35)% | 57.33 | 37.28 | 57.33 | 110.80 | ||||||||||||||||||||
WTI |
||||||||||||||||||||||||||
Average |
42.18 | (42)% | 73.15 | 48.80 | 93.00 | 97.97 | ||||||||||||||||||||
End of Period |
37.04 | (30)% | 53.27 | 37.04 | 53.27 | 98.42 | ||||||||||||||||||||
Average Differential Brent-WTI |
2.53 | (34)% | 3.83 | 4.84 | 6.51 | 10.79 | ||||||||||||||||||||
WCS (2) |
||||||||||||||||||||||||||
Average |
27.69 | (53)% | 58.91 | 35.28 | 73.60 | 72.77 | ||||||||||||||||||||
End of Period |
24.98 | (34)% | 37.59 | 24.98 | 37.59 | 74.80 | ||||||||||||||||||||
Average Differential WTI-WCS |
14.49 | 2% | 14.24 | 13.52 | 19.40 | 25.20 | ||||||||||||||||||||
Condensate (C5 @ Edmonton) (3) |
||||||||||||||||||||||||||
Average |
41.67 | (41)% | 70.57 | 47.36 | 92.95 | 101.69 | ||||||||||||||||||||
Average Differential WTI-Condensate (Premium)/Discount |
0.51 | (80)% | 2.58 | 1.44 | 0.05 | (3.72) | ||||||||||||||||||||
Average Differential WCS-Condensate (Premium)/Discount |
(13.98) | 20% | (11.66) | (12.08) | (19.35) | (28.92) | ||||||||||||||||||||
Average Refined Product Prices (US$/bbl) |
||||||||||||||||||||||||||
Chicago Regular Unleaded Gasoline (RUL) |
55.24 | (32)% | 81.26 | 67.68 | 107.40 | 116.35 | ||||||||||||||||||||
Chicago Ultra-low Sulphur Diesel (ULSD) |
59.23 | (42)% | 101.48 | 68.12 | 117.55 | 126.31 | ||||||||||||||||||||
Refining Margin: Average 3-2-1 Crack Spreads (US$/bbl) |
||||||||||||||||||||||||||
Chicago |
14.47 | (1)% | 14.60 | 19.11 | 17.61 | 21.77 | ||||||||||||||||||||
Group 3 |
13.82 | 4% | 13.28 | 18.16 | 16.27 | 20.80 | ||||||||||||||||||||
Average Natural Gas Prices |
||||||||||||||||||||||||||
AECO (C$/Mcf) |
2.65 | (34)% | 4.01 | 2.77 | 4.42 | 3.17 | ||||||||||||||||||||
NYMEX (US$/Mcf) |
2.27 | (43)% | 4.00 | 2.66 | 4.42 | 3.65 | ||||||||||||||||||||
Basis Differential NYMEX-AECO (US$/Mcf) |
0.27 | (39)% | 0.44 | 0.49 | 0.40 | 0.58 | ||||||||||||||||||||
Foreign Exchange Rates (US$ per C$1) |
||||||||||||||||||||||||||
Average |
0.749 | (15)% | 0.881 | 0.782 | 0.905 | 0.971 |
(1) | These benchmark prices do not reflect our realized sales prices. For our average realized sales prices and realized risk management results, refer to the operating netbacks table in the Operating Results section of this MD&A. |
(2) | The average Canadian dollar WCS benchmark price for 2015 was $45.12 per barrel (2014 $81.33 per barrel; 2013 $74.94 per barrel); fourth quarter average WCS benchmark price was $36.97 per barrel (2014 $66.87 per barrel). |
(3) | The average Canadian dollar condensate benchmark price for 2015 was $60.56 per barrel (2014 $102.71 per barrel; 2013 $104.73 per barrel); fourth quarter average condensate benchmark price was $55.63 per barrel (2014 $80.10 per barrel). |
Cenovus Energy Inc. | 6 | 2015 Managements Discussion and Analysis |
Crude Oil Benchmarks
The average Brent, WTI and WCS benchmark prices continued to be impacted by a global imbalance of supply and demand which began in the second half of 2014. This imbalance, created by weak global demand for oil and strong growth in North American crude oil supply, was further amplified by the sustained decision of the Organization of Petroleum Exporting Countries (OPEC) to maintain its level of crude oil output and discontinue its role as the swing supplier of crude oil. Despite significantly lower crude oil prices and increased global demand in 2015, the imbalance has only slightly improved. Economic uncertainty in China, resilient U.S. production, continued strong production from Saudi Arabia and Iraq, as well as concerns regarding the return of Iranian production have contributed to sustained low crude oil prices.
The Brent benchmark is representative of global crude oil prices and, we believe, a better indicator than WTI of inland refined product prices.
WTI is an important benchmark for Canadian crude oil since it reflects inland North American crude oil prices and its Canadian dollar equivalent is the basis for determining royalties for a number of our crude oil properties. The average Brent-WTI differential narrowed compared with 2014. WTI benchmark prices strengthened relative to Brent as a result of high global crude oil inventory levels and continued strong demand in the U.S., leaving transportation costs as the primary driver of the Brent-WTI differential.
WCS is blended heavy oil which consists of both conventional heavy oil and unconventional diluted bitumen. The average WTI-WCS differential narrowed in 2015. The narrower differential resulted primarily from increased demand for WCS due to new pipeline infrastructure to the U.S. Gulf Coast, growing rail capacity and the slow return of heavy crude oil supply forced offline due to forest fires in northeastern Alberta during the second quarter of 2015.
Blending condensate with bitumen and heavy oil enables our production to be transported through pipelines. Our blending ratios range from approximately 10 percent to 33 percent. The WCS-Condensate differential is an important benchmark as a narrower differential generally results in an increase in the recovery of condensate costs when selling a barrel of blended crude oil. When the supply of condensate in Alberta does not meet the demand, Edmonton condensate prices may be driven by U.S. Gulf Coast condensate prices plus the value attributed to transporting the condensate to Edmonton.
The average WCS-Condensate differential narrowed in 2015 due to condensate supply growth as well as improved diluent transportation infrastructure for condensate imports into Alberta and heavy oil exports to market.
Refining Benchmarks
The Chicago Regular Unleaded Gasoline (RUL) and Chicago Ultra-low Sulphur Diesel (ULSD) benchmark prices are representative of inland refined product prices and are used to derive the Chicago 3-2-1 crack spread. The 3-2-1 crack spread is an indicator of the refining margin generated by converting three barrels of crude oil into two barrels of regular unleaded gasoline and one barrel of ultra-low sulphur diesel using current month WTI based crude oil feedstock prices and valued on a last in, first out accounting basis.
Average Chicago 3-2-1 crack spreads increased in 2015 compared with 2014 driven by stronger product demand. Average Group 3 crack spreads increased as a major unplanned refinery outage in August 2015 caused product inventory drawdowns during the driving season.
Our realized crack spreads are affected by many other factors such as the variety of feedstock crude oil, refinery configuration and product output, the time lag between the purchase and delivery of crude oil feedstock, and the cost of feedstock which is valued on a first in, first out (FIFO) accounting basis.
Cenovus Energy Inc. | 7 | 2015 Managements Discussion and Analysis |
Natural Gas Benchmarks
Average natural gas prices decreased in 2015 primarily due to increased supply from the U.S. and Canada.
Foreign Exchange Benchmarks
Revenues are subject to foreign exchange exposure as the sales prices of our crude oil, natural gas and refined products are determined by reference to U.S. benchmark prices. A decrease in the value of the Canadian dollar compared with the U.S. dollar has a positive impact on our reported results. Likewise, as the Canadian dollar strengthens, our reported results are lower. In addition to our revenues being denominated in U.S. dollars, we have chosen to borrow U.S. dollar long-term debt. In periods of a weakening Canadian dollar, our U.S. dollar debt gives rise to unrealized foreign exchange losses when translated to Canadian dollars.
In 2015 compared with 2014, the Canadian dollar weakened relative to the U.S. dollar due to lower commodity prices, strengthening of the U.S. economy, and Canadian political and economic uncertainty. The weakening of the Canadian dollar compared with 2014 had a positive impact of approximately $1,772 million on our revenues and also resulted in $1,064 million of unrealized foreign exchange losses on the translation of our U.S. dollar debt.
Selected Consolidated Financial Results
Sustained low commodity prices in 2015 significantly impacted our financial results. The following key performance measures are discussed in more detail within this MD&A.
($ millions, except per share amounts) | 2015 |
Percent Change |
2014 |
Percent Change |
2013 | |||||||||||||||||
Revenues |
13,064 | (33)% | 19,642 | 5% | 18,657 | |||||||||||||||||
Operating Cash Flow (1) (2) |
2,439 | (42)% | 4,179 | (7)% | 4,484 | |||||||||||||||||
Cash Flow (1) |
1,691 | (51)% | 3,479 | (4)% | 3,609 | |||||||||||||||||
Per Share Diluted |
2.07 | (55)% | 4.59 | (4)% | 4.76 | |||||||||||||||||
Operating Earnings (Loss) (1) |
(403 | ) | (164)% | 633 | (46)% | 1,171 | ||||||||||||||||
Per Share Diluted |
(0.49 | ) | (158)% | 0.84 | (46)% | 1.55 | ||||||||||||||||
Net Earnings (Loss) |
618 | (17)% | 744 | 12% | 662 | |||||||||||||||||
Per Share Basic |
0.75 | (23)% | 0.98 | 11% | 0.88 | |||||||||||||||||
Per Share Diluted |
0.75 | (23)% | 0.98 | 13% | 0.87 | |||||||||||||||||
Total Assets |
25,791 | 4% | 24,695 | (2)% | 25,224 | |||||||||||||||||
Total Long-Term Financial Liabilities (3) |
6,552 | 19% | 5,484 | (10)% | 6,113 | |||||||||||||||||
Capital Investment (4) |
1,714 | (44)% | 3,051 | (6)% | 3,262 | |||||||||||||||||
Dividends |
||||||||||||||||||||||
Cash Dividends |
528 | (34)% | 805 | 10% | 732 | |||||||||||||||||
In Shares from Treasury |
182 | - | - | - | - | |||||||||||||||||
Per Share |
0.8524 | (20)% | 1.0648 | 10% | 0.968 |
(1) | Non-GAAP measure defined in this MD&A. |
(2) | For all periods presented, we reclassified employee long-term incentive costs from operating expenses to general and administrative costs. There were no changes to Cash Flow, Operating Earnings or Net Earnings. |
(3) | Includes Long-Term Debt, Partnership Contribution Payable, Risk Management Liability and other financial liabilities included within Other Liabilities on the Consolidated Balance Sheets. |
(4) | Includes expenditures on Property, Plant and Equipment (PP&E) and Exploration and Evaluation (E&E) assets. |
Cenovus Energy Inc. | 8 | 2015 Managements Discussion and Analysis |
Revenues
($ millions) | 2015 vs. 2014 |
2014 vs. 2013 |
||||||||
Revenues, Comparative Year |
19,642 | 18,657 | ||||||||
Increase (Decrease) due to: |
||||||||||
Oil Sands |
(1,799) | 1,020 | ||||||||
Conventional |
(1,401) | 220 | ||||||||
Refining and Marketing |
(3,853) | (48) | ||||||||
Corporate and Eliminations |
475 | (207) | ||||||||
Revenues, End of Year |
13,064 | 19,642 |
Combined Oil Sands and Conventional revenues declined 41 percent in 2015 due to lower crude oil blend and natural gas sales prices, partially offset by higher crude oil sales volumes, weakening of the Canadian dollar relative to the U.S. dollar and lower royalties. The sale of our royalty interest and mineral fee title lands business also reduced revenues.
Revenues from our Refining and Marketing segment decreased 30 percent from 2014. Refining revenues declined due to the decrease in refined product pricing, consistent with lower Chicago RUL and Chicago ULSD benchmark prices. The decrease in our reported revenues was partially offset by the weakening of the Canadian dollar relative to the U.S. dollar. Revenues from third-party crude oil and natural gas sales undertaken by the marketing group in 2015 decreased 36 percent from 2014, primarily due to a decline in sales prices, partially offset by an increase in purchased crude oil volumes.
Corporate and Eliminations revenues relate to sales and operating revenues between segments and are recorded at transfer prices based on current market prices.
Overall, revenues increased in 2014 compared with 2013 primarily due to higher blended crude oil sales volumes and higher average sales prices for blended crude oil and natural gas, partially offset by an increase in royalties.
Further information regarding our revenues can be found in the Reportable Segments section of this MD&A.
Operating Cash Flow
Operating Cash Flow is a non-GAAP measure used to provide a consistent measure of the cash generating performance of our assets for comparability of our underlying financial performance between periods. Operating Cash Flow 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. Items within the Corporate and Eliminations segment are excluded from the calculation of Operating Cash Flow.
($ millions) | 2015 | 2014 | 2013 | |||||||||||||
Revenues |
13,401 | 20,454 | 19,262 | |||||||||||||
(Add) Deduct: |
||||||||||||||||
Purchased Product |
7,709 | 11,767 | 11,004 | |||||||||||||
Transportation and Blending |
2,045 | 2,477 | 2,074 | |||||||||||||
Operating Expenses (1) |
1,846 | 2,051 | 1,787 | |||||||||||||
Production and Mineral Taxes |
18 | 46 | 35 | |||||||||||||
Realized (Gain) Loss on Risk Management Activities |
(656) | (66) | (122) | |||||||||||||
Operating Cash Flow |
2,439 | 4,179 | 4,484 |
(1) | For all periods presented, we reclassified employee long-term incentive costs from operating expenses to general and administrative costs. |
Operating Cash Flow declined 42 percent in 2015 primarily due to:
| A 50 percent decrease in our average crude oil sales price and a 33 percent decrease in our average natural gas sales price, consistent with lower associated benchmark prices; and |
| A 10 percent decline in our natural gas sales volumes. |
Cenovus Energy Inc. | 9 | 2015 Managements Discussion and Analysis |
These declines to Operating Cash Flow were partially offset by:
| Realized risk management gains of $613 million, excluding Refining and Marketing, compared with $39 million in 2014; |
| Lower royalties primarily due to a decrease in crude oil sales prices; |
| A decrease of $3.42 per barrel in crude oil operating expenses primarily due to a decline in workover activities, a reduction in fuel costs due to lower natural gas prices, and lower repairs and maintenance costs; |
| Higher Operating Cash Flow from Refining and Marketing as a result of improved margins on the sale of secondary products, such as coke and asphalt, and weakening of the Canadian dollar relative to the U.S. dollar, partially offset by higher heavy crude oil feedstock costs relative to the WTI benchmark price and higher operating costs; and |
| An inventory write-down of $66 million compared with an inventory write-down of $131 million in 2014. |
Operating Cash Flow Variance
Additional details explaining the changes in Operating Cash Flow can be found in the Reportable Segments section of this MD&A.
Cash Flow
Cash Flow is a non-GAAP measure commonly used in the oil and gas industry to assist in measuring a companys ability to finance its capital programs and meet its financial obligations. Cash Flow is defined as cash from operating activities excluding net change in other assets and liabilities and net change in non-cash working capital.
($ millions) | 2015 | 2014 | 2013 | |||||||||||||
Cash From Operating Activities |
1,474 | 3,526 | 3,539 | |||||||||||||
(Add) Deduct: |
||||||||||||||||
Net Change in Other Assets and Liabilities |
(107) | (135) | (120) | |||||||||||||
Net Change in Non-Cash Working Capital |
(110) | 182 | 50 | |||||||||||||
Cash Flow |
1,691 | 3,479 | 3,609 |
In 2015, Cash Flow decreased due to a combination of lower Operating Cash Flow, as discussed above, and higher current income tax. Current income tax rose due to the timing of recognition of partnership income for tax purposes.
Operating Earnings (Loss)
Operating Earnings (Loss) is a non-GAAP measure used to provide a consistent measure of the comparability of our underlying financial performance between periods by removing non-operating items. Operating Earnings (Loss) is defined as Earnings (Loss) 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, foreign exchange gains (losses) on settlement of intercompany transactions, gains (losses) on divestiture of assets, less income taxes on Operating Earnings (Loss) before tax, excluding the effect of changes in statutory income tax rates and the recognition of an increase in U.S. tax basis.
Cenovus Energy Inc. | 10 | 2015 Managements Discussion and Analysis |
($ millions) | 2015 | 2014 | 2013 | |||||||||||||
Earnings, Before Income Tax |
537 | 1,195 | 1,094 | |||||||||||||
Add (Deduct): |
||||||||||||||||
Unrealized Risk Management (Gain) Loss (1) |
195 | (596 | ) | 415 | ||||||||||||
Non-operating Unrealized Foreign Exchange (Gain) Loss (2) |
1,064 | 458 | 52 | |||||||||||||
Realized Foreign Exchange Loss on Early Receipt of the Partnership Contribution Receivable |
- | - | 146 | |||||||||||||
(Gain) Loss on Divestiture of Assets |
(2,392 | ) | (156 | ) | 1 | |||||||||||
Operating Earnings (Loss), Before Income Tax |
(596 | ) | 901 | 1,708 | ||||||||||||
Income Tax Expense (Recovery) |
(193 | ) | 268 | 537 | ||||||||||||
Operating Earnings (Loss) |
(403 | ) | 633 | 1,171 |
(1) | Includes the reversal of unrealized (gains) losses recorded in prior periods. |
(2) | Includes unrealized foreign exchange (gains) losses on translation of U.S. dollar denominated notes issued from Canada and foreign exchange (gains) losses on settlement of intercompany transactions. |
Operating Earnings decreased compared with 2014 primarily due to lower Cash Flow, and higher depreciation, depletion and amortization (DD&A) and exploration expense due to asset impairments. These items were partially offset by a recovery of deferred income tax compared with an expense in 2014 and a goodwill impairment of $497 million recorded in 2014.
Net Earnings
($ millions) | 2015 vs. 2014 |
2014 vs. 2013 |
||||||||
Net Earnings, Comparative Year |
744 | 662 | ||||||||
Increase (Decrease) due to: |
||||||||||
Operating Cash Flow (1) (2) |
(1,740 | ) | (305 | ) | ||||||
Corporate and Eliminations: |
||||||||||
Unrealized Risk Management Gain (Loss) |
(791 | ) | 1,011 | |||||||
Unrealized Foreign Exchange Gain (Loss) |
(686 | ) | (371 | ) | ||||||
Gain (Loss) on Divestiture of Assets |
2,236 | 157 | ||||||||
Expenses (2) (3) |
46 | 191 | ||||||||
Depreciation, Depletion and Amortization |
(168 | ) | (113 | ) | ||||||
Goodwill Impairment |
497 | (497 | ) | |||||||
Exploration Expense |
(52 | ) | 28 | |||||||
Income Tax Expense |
532 | (19 | ) | |||||||
Net Earnings, End of Year |
618 | 744 |
(1) | Non-GAAP measure defined in this MD&A. |
(2) | For all periods presented, we reclassified employee long-term incentive costs from operating expenses to general and administrative costs. |
(3) | Includes general and administrative, finance costs, interest income, realized foreign exchange (gains) losses, research costs, other (income) loss, net and Corporate and Eliminations revenues, purchased product, transportation and blending, and operating expenses. |
In 2015, Net Earnings declined as an after-tax gain of approximately $1.9 billion from the divestiture of our royalty interest and mineral fee title lands business, and a deferred tax recovery related to non-operating items compared with an expense in 2014, were more than offset by:
| A decline in Operating Earnings, as discussed above; |
| Unrealized risk management losses, after-tax, of $141 million (2014 unrealized gains of $444 million); and |
| Non-operating unrealized foreign exchange losses, after-tax, of $1,064 million (2014 $458 million). |
Net Earnings increased in 2014 compared with 2013 primarily due to unrealized risk management gains compared with losses in 2013, a gain on the sale of non-core assets and no realized foreign exchange loss in 2014 related to the Partnership Contribution Receivable, partially offset by a decline in operating earnings and higher non-operating unrealized foreign exchange losses.
Net Capital Investment
($ millions) | 2015 | 2014 | 2013 | |||||||||||||||||
Oil Sands |
1,185 | 1,986 | 1,885 | |||||||||||||||||
Conventional |
244 | 840 | 1,189 | |||||||||||||||||
Refining and Marketing |
248 | 163 | 107 | |||||||||||||||||
Corporate and Eliminations |
37 | 62 | 81 | |||||||||||||||||
Capital Investment |
1,714 | 3,051 | 3,262 | |||||||||||||||||
Acquisitions |
87 | 18 | 32 | |||||||||||||||||
Divestitures |
(3,344 | ) | (277 | ) | (283 | ) | ||||||||||||||
Net Capital Investment (1) |
(1,543 | ) | 2,792 | 3,011 |
(1) | Includes expenditures on PP&E and E&E. |
Cenovus Energy Inc. | 11 | 2015 Managements Discussion and Analysis |
Capital investment in 2015 declined 44 percent as we reduced our capital investment in light of the low commodity price environment.
In 2015, Oil Sands capital investment focused on sustaining capital related to existing production, the phase G expansion at Foster Creek, and Christina Lake optimization project and phase F expansion. We drilled 164 gross stratigraphic test wells at Foster Creek and Christina Lake to determine pad placement for sustaining wells and near-term expansion phases.
Conventional capital investment focused on maintenance capital and spending for our CO2 enhanced oil recovery project at Weyburn and drilling activity in the second half of the year at our tight oil projects in southeast Alberta.
Capital investment in the Refining and Marketing segment focused on the debottlenecking project at Wood River, in addition to capital maintenance, projects improving our refinery reliability and safety, and environmental initiatives.
Further information regarding our capital investment can be found in the Reportable Segments section of this MD&A.
Acquisitions and Divestitures
In 2015, we completed the sale of our royalty interest and mineral fee title lands business for cash proceeds of approximately $3.3 billion, recording an after-tax gain of approximately $1.9 billion. The sale included approximately 4.8 million gross acres of royalty interest and mineral fee title lands in Alberta, Saskatchewan and Manitoba. A royalty on Cenovuss working interest production on these fee lands and a Gross Overriding Royalty (GORR) on production from our Pelican Lake and Weyburn assets were also included.
In 2015, we purchased a crude-by-rail terminal for $75 million, plus adjustments, to expand our portfolio of transportation options.
Divestitures in 2014 primarily included the sale of certain of our Bakken assets in southeastern Saskatchewan and the sale of certain of our Wainwright assets in Alberta for net proceeds of $269 million, resulting in a gain of $153 million. In 2013, divestitures included the sale of our Lower Shaunavon asset for net proceeds of $241 million, resulting in a loss of $2 million.
We had no material acquisitions in 2014 or 2013.
Capital Investment Decisions
Our disciplined approach to capital allocation includes prioritizing our uses of cash flow in the following manner:
| First, to capital for our existing business operations; |
| Second, to paying a dividend as part of providing strong total shareholder return; and |
| Third, for growth or discretionary capital. |
Our approach to capital allocation includes evaluating all opportunities using specific rigorous criteria within the context of achieving our objectives of maintaining a prudent and flexible capital structure and strong balance sheet metrics, which position us to be financially resilient in times of lower cash flow. In addition, we continue to evaluate other corporate and financial opportunities, including generating cash from our existing portfolio. Refer to the Liquidity and Capital Resources section of this MD&A for further information.
($ millions) | 2015 | 2014 | 2013 | |||||||||||||
Cash Flow (1) |
1,691 | 3,479 | 3,609 | |||||||||||||
Capital Investment (Committed and Growth) |
1,714 | 3,051 | 3,262 | |||||||||||||
Free Cash Flow (2) |
(23 | ) | 428 | 347 | ||||||||||||
Cash Dividends |
528 | 805 | 732 | |||||||||||||
(551 | ) | (377 | ) | (385 | ) |
(1) | Non-GAAP measure defined in this MD&A. |
(2) | Free Cash Flow is a non-GAAP measure defined as Cash Flow less capital investment. |
We expect our capital investment for 2016 to be funded from internally generated cash flow and our cash balance on hand.
Cenovus Energy Inc. | 12 | 2015 Managements Discussion and Analysis |
Corporate and Eliminations, which primarily includes unrealized gains and losses recorded on derivative financial instruments, gains and losses on divestiture of assets, as well as other Cenovus-wide costs for general and administrative, financing activities and research costs. As financial instruments are settled, the realized gains and losses are recorded in the operating segment to which the derivative instrument relates. Eliminations relate to sales and operating revenues, and purchased product between segments, recorded at transfer prices based on current market prices, and to unrealized intersegment profits in inventory.
Revenues by Reportable Segment
($ millions) | 2015 | 2014 | 2013 | |||||||||||||
Oil Sands |
3,001 | 4,800 | 3,780 | |||||||||||||
Conventional |
1,595 | 2,996 | 2,776 | |||||||||||||
Refining and Marketing |
8,805 | 12,658 | 12,706 | |||||||||||||
Corporate and Eliminations |
(337 | ) | (812 | ) | (605 | ) | ||||||||||
13,064 | 19,642 | 18,657 |
In northeastern Alberta, we are a 50 percent partner in the Foster Creek, Christina Lake and Narrows Lake oil sands projects. We have several emerging projects in the early stages of development, including our 100 percent-owned projects at Telephone Lake and Grand Rapids. The Oil Sands segment also includes the Athabasca natural gas property, from which a portion of the natural gas production is used as fuel at the adjacent Foster Creek operations.
Significant developments in our Oil Sands segment in 2015 compared with 2014 include:
| Production at Foster Creek increasing 10 percent, to an average of 65,345 barrels per day, primarily as a result of the ramp-up of phase F, partially offset by the impact of a forest fire in the second quarter. Fourth quarter production was lower compared with 2014. Improved wellbore conformance accelerated production from more mature wells, resulting in faster declines from these wells. To preserve capital, we chose in 2015 to defer some planned well pads, which combined with the faster declines, contributed to lower fourth quarter volumes. In addition, while well downtime at Foster Creek was within expected ranges for 2015, a higher than average number of wells were down for servicing in the second half of the year, which further impacted production; |
| Christina Lake production increasing nine percent, to an average of 74,975 barrels per day primarily due to production from additional wells, and improved performance of our facilities; |
| Completion of the optimization project at Christina Lake, which is expected to add 22,000 barrels per day of gross production capacity. Incremental production from the project is anticipated in 2016; |
| Reducing our crude oil operating costs by $104 million or $3.37 per barrel; and |
| Receiving regulatory approval for Christina Lake phase H, a 50,000 gross barrels per day phase. |
Cenovus Energy Inc. | 13 | 2015 Managements Discussion and Analysis |
Oil Sands Crude Oil
Financial and Per-unit Results
2015 | 2014 | 2013 | ||||||||||||||||||||||||||||||||
($ millions, unless otherwise noted) | $ per-unit (1) | $ per-unit (1) | $ per-unit (1) | |||||||||||||||||||||||||||||||
Gross Sales |
3,000 | 60 | 4,963 | 109 | 3,850 | 103 | ||||||||||||||||||||||||||||
Less: Royalties |
29 | 1 | 233 | 5 | 131 | 4 | ||||||||||||||||||||||||||||
Revenues |
2,971 | 59 | 4,730 | 104 | 3,719 | 99 | ||||||||||||||||||||||||||||
Expenses |
||||||||||||||||||||||||||||||||||
Transportation and Blending |
1,814 | 36 | 2,130 | 47 | 1,748 | 47 | ||||||||||||||||||||||||||||
Operating (2) |
511 | 10 | 615 | 14 | 527 | 14 | ||||||||||||||||||||||||||||
(Gain) Loss on Risk Management |
(400 | ) | (8 | ) | (38 | ) | (1 | ) | (33 | ) | (1 | ) | ||||||||||||||||||||||
Operating Cash Flow |
1,046 | 21 | 2,023 | 44 | 1,477 | 39 | ||||||||||||||||||||||||||||
Capital Investment |
1,184 | 1,980 | 1,880 | |||||||||||||||||||||||||||||||
Operating Cash Flow Net of Related Capital Investment |
(138 | ) | 43 | (403 | ) |
(1) | Per-unit amounts are calculated on an unblended crude oil basis. |
(2) | For all periods presented, we reclassified employee long-term incentive costs from operating expenses to general and administrative costs. |
Capital investment in excess of Operating Cash Flow from Oil Sands was funded through Operating Cash Flow generated by our Conventional and Refining and Marketing segments in 2015 and 2013. Proceeds from our common share issuance and the sale of our royalty interest and mineral fee title lands business also contributed to funding our capital investment in 2015.
Operating Cash Flow Variance
(1) | Revenues include the value of condensate sold as heavy oil blend. Condensate costs are recorded in transportation and blending expense. The crude oil price excludes the impact of condensate purchases. |
Revenues
Pricing
In 2015, our average crude oil sales price was $30.88 per barrel, a 53 percent decrease from 2014 as the prices we received were adversely impacted by the worldwide low commodity price environment. The decline in our crude oil price was consistent with the decrease in the WCS and CDB benchmark prices, partially offset by weakening of the Canadian dollar relative to the U.S. dollar and increased sales into the U.S. market which generally secure a higher sales price. The WCS-CDB differential narrowed by 40 percent to a discount of US$2.37 per barrel (2014 a discount of US$3.94 per barrel), primarily due to greater access to refineries on the U.S. Gulf Coast that can process a wider variety of heavier crude oils. In 2015, 86 percent of our Christina Lake production was sold as CDB (2014 88 percent), with the remainder sold into the WCS stream. Christina Lake production, whether sold as CDB or blended with WCS and subject to a quality equalization charge, is priced at a discount to WCS.
Production Volumes
(barrels per day) | 2015 |
Percent Change |
2014 |
Percent Change |
2013 | |||||||||||||||||||||||
Foster Creek |
65,345 | 10% | 59,172 | 11% | 53,190 | |||||||||||||||||||||||
Christina Lake |
74,975 | 9% | 69,023 | 40% | 49,310 | |||||||||||||||||||||||
140,320 | 9% | 128,195 | 25% | 102,500 |
Foster Creek production increased in 2015 primarily due to the ramp-up of phase F and production from additional wells. The ramp-up of phase F, our eleventh oil sands phase, is expected to take approximately 18 months from start-up, which occurred in the third quarter of 2014. Production increases were partially offset when production at Foster Creek was shut down for 11 full days as a safety precaution due to a nearby forest fire. The forest fire decreased production by approximately 2,600 barrels per day. Fourth quarter production was lower compared with 2014. Improved wellbore conformance accelerated production from more mature wells, resulting in faster declines from these wells. To preserve capital, we chose in 2015 to defer some planned well pads, which combined with the faster declines, contributed to lower fourth quarter volumes. In addition, while well downtime at Foster Creek was within expected ranges for 2015, a higher than average number of wells were down for servicing in the second half of the year, which further impacted production.
Cenovus Energy Inc. | 14 | 2015 Managements Discussion and Analysis |
Production from Christina Lake increased in 2015 due to production from additional wells, phase E reaching nameplate production capacity in the second quarter of 2014, and improved performance of our facilities.
Condensate
The bitumen currently produced by Cenovus must be blended with condensate to reduce its thickness in order to transport it to market. Revenues represent the total value of blended crude oil sold and include the value of condensate.
Royalties
Royalty calculations for our oil sands projects are based on government prescribed pre- and post-payout royalty rates which are determined on a sliding scale using the Canadian dollar equivalent WTI benchmark price. Royalty calculations differ between properties.
Royalties at Foster Creek, a post-payout project, are based on an annualized calculation which uses the greater of: (1) the gross revenues multiplied by the applicable royalty rate (one to nine percent, based on the Canadian dollar equivalent WTI benchmark price); or (2) the net profits of the project multiplied by the applicable royalty rate (25 to 40 percent, based on the Canadian dollar equivalent WTI benchmark price). Gross revenues are a function of sales volumes and realized sales prices. Net profits are a function of sales volumes, realized sales prices and allowed operating and capital costs.
Royalties at Christina Lake, a pre-payout project, are based on a monthly calculation that applies a royalty rate (ranging from one to nine percent, based on the Canadian dollar equivalent WTI benchmark price) to the gross revenues from the project.
Effective Royalty Rates
(percent) | 2015 | 2014 | 2013 | |||||||||||||
Foster Creek |
1.9 | 8.8 | 5.8 | |||||||||||||
Christina Lake |
2.8 | 7.5 | 6.8 |
Royalties decreased $204 million, primarily related to the decline in crude oil sales prices, partially offset by an increase in sales volumes. At Foster Creek, the royalty calculation was based on gross revenues as compared with a calculation based on net profits for 2014. In the first quarter of 2015, we received regulatory approval to include certain capital costs incurred in previous years in our royalty calculation and recorded an associated credit, decreasing the overall royalty rate. Excluding the credit, the effective royalty rate for Foster Creek would have been 3.1 percent in 2015. The Christina Lake royalty rate decreased in 2015 as a result of lower realized sales prices.
Expenses
Transportation and Blending
Transportation and blending costs decreased $316 million or 15 percent. Blending costs declined primarily due to lower condensate prices, partially offset by an increase in condensate volumes, consistent with the rise in production. In 2015, we recorded a $44 million (2014 $6 million) write-down of our blended crude oil and condensate inventory to net realizable value as a result of the decline in crude oil prices. Our condensate costs were higher than the average benchmark price in 2015 primarily due to the utilization of higher-priced inventory and the transportation costs associated with moving the condensate to our oil sands projects.
Transportation costs increased primarily due to higher pipeline tariffs and higher tariffs from additional sales to the U.S. market, which generally secure higher sales prices. To help ensure adequate capacity for our expected future production growth, we have capacity commitments in excess of our current production. Future production growth is expected to reduce our per-barrel transportation costs.
We incurred higher transportation charges on the Trans Mountain pipeline system, with our long-term commitment for firm service. Transportation costs also increased as lower volumes moved by rail were more than offset by new lease costs for railcars, and higher loading fees and storage costs. In 2015, we transported an average of 7,057 gross barrels per day of crude oil by rail, consisting of 43 unit train shipments (2014 7,325 gross barrels per day, 47 unit train shipments).
Operating
Primary drivers of our operating expenses for 2015 were workforce, fuel, repairs and maintenance, chemical costs and workovers. Total operating expenses decreased $104 million or $3.37 per barrel, primarily as a result of lower natural gas prices that reduced fuel costs, higher production, a decline in workover activities and efforts from our supply chain management.
Cenovus Energy Inc. | 15 | 2015 Managements Discussion and Analysis |
Per-unit Operating Expenses
($/bbl) | 2015 | Percent Change |
2014 | Percent Change |
2013 | |||||||||||||||||||||||
Foster Creek |
||||||||||||||||||||||||||||
Fuel |
2.80 | (37)% | 4.46 | 55% | 2.88 | |||||||||||||||||||||||
Non-fuel (1) |
9.80 | (18)% | 11.89 | (7)% | 12.74 | |||||||||||||||||||||||
Total |
12.60 | (23)% | 16.35 | 5% | 15.62 | |||||||||||||||||||||||
Christina Lake |
||||||||||||||||||||||||||||
Fuel |
2.20 | (40)% | 3.65 | 20% | 3.03 | |||||||||||||||||||||||
Non-fuel (1) |
5.81 | (22)% | 7.44 | (20)% | 9.34 | |||||||||||||||||||||||
Total |
8.01 | (28)% | 11.09 | (10)% | 12.37 | |||||||||||||||||||||||
Total |
10.13 | (25)% | 13.50 | (4)% | 14.07 |
(1) | For all periods presented, we reclassified employee long-term incentive costs from operating expenses to general and administrative costs. |
At Foster Creek, fuel costs decreased due to lower natural gas prices and a decline in fuel consumption on a per-barrel basis. Non-fuel operating expenses declined primarily due to:
| Higher production volumes; |
| A reduction in workover expenses due to lower costs associated with well servicing and pump changes; and |
| Lower electricity costs. |
Foster Creek non-fuel operating expenses included approximately $2.6 million or $0.11 per barrel of incremental costs associated with the shut-down due to a nearby forest fire that occurred in the second quarter of 2015.
At Christina Lake, fuel costs decreased due to lower natural gas prices and a decrease in fuel consumption on a per-barrel basis. Non-fuel operating expenses decreased primarily due to:
| Increased production; |
| Lower workover costs related to fewer pump changes; and |
| A decrease in repairs and maintenance costs due to a focus on critical operational activities and no turnaround costs in 2015. |
Operating Netbacks
(1) | The heavy oil price and transportation and blending costs exclude the cost of purchased condensate which is blended with the heavy oil. On a per-barrel of unblended crude oil basis, the cost of condensate in 2015 was $27.44 per barrel (2014 $42.01 per barrel; 2013 $42.41 per barrel) for Foster Creek, and $29.50 per barrel (2014 $45.45 per barrel; 2013 $45.25 per barrel) for Christina Lake. Our blending ratios range from approximately 25 percent to 33 percent. |
(2) | The netbacks do not reflect non-cash write-downs of product inventory in 2015 and 2014. There was no product inventory write-down recorded in 2013. |
Risk Management
Risk management activities in 2015 resulted in realized gains of $400 million (2014 $38 million), consistent with our contract prices exceeding average benchmark prices.
Oil Sands Natural Gas
Oil Sands includes our natural gas operations in northeastern Alberta. A portion of the natural gas produced from our Athabasca property is used as fuel at Foster Creek. Our natural gas production for 2015, net of internal usage, was 19 MMcf per day (2014 22 MMcf per day). Operating Cash Flow was $10 million in 2015 (2014 $46 million) primarily due to the decline in natural gas sales prices.
Cenovus Energy Inc. | 16 | 2015 Managements Discussion and Analysis |
Oil Sands Capital Investment
($ millions) | 2015 | 2014 | 2013 | |||||||||||||
Foster Creek |
403 | 796 | 797 | |||||||||||||
Christina Lake |
647 | 794 | 688 | |||||||||||||
1,050 | 1,590 | 1,485 | ||||||||||||||
Narrows Lake |
47 | 175 | 152 | |||||||||||||
Telephone Lake |
24 | 112 | 93 | |||||||||||||
Grand Rapids |
38 | 63 | 39 | |||||||||||||
Other (1) |
26 | 46 | 116 | |||||||||||||
Capital Investment (2) |
1,185 | 1,986 | 1,885 |
(1) | Includes new resource plays and Athabasca natural gas. |
(2) | Includes expenditures on PP&E and E&E assets. |
Existing Projects
Capital investment at Foster Creek in 2015 focused on sustaining capital related to existing production, expansion phase G and the drilling of stratigraphic test wells. In 2015, capital investment declined mainly due to the start-up of phase F in the third quarter of 2014.
In 2015, Christina Lake capital investment focused on sustaining capital related to existing production, expansion phases F and G, and the optimization project. The optimization project has been completed and is expected to add 22,000 barrels per day of gross production capacity. Incremental production from the optimization project is anticipated in 2016. Capital investment in 2015 decreased from 2014 due to lower spending on phase F facilities, partially offset by increased investment in sustaining activities.
Capital investment at Narrows Lake in 2015 was mainly on detailed engineering and construction wind-down. Capital investment declined in 2015 compared with 2014 due to the suspension of construction at Narrows Lake.
Emerging Projects
In 2015, Telephone Lake capital investment focused primarily on completing front-end engineering work on the central processing facility and preliminary infrastructure development. Capital spending decreased in 2015 as we did not drill any stratigraphic test wells during the year (2014 45 stratigraphic test wells).
Capital investment at Grand Rapids in 2015 focused on continued operation of the SAGD pilot project. A third well pair was drilled, completed and commenced steam circulation. Capital investment decreased in 2015 compared with 2014 as there were no stratigraphic test wells drilled in 2015 (2014 10 stratigraphic test wells) and all work related to the dismantling and removal of an existing SAGD facility purchased in 2014 was completed.
Drilling Activity (1)
Gross Stratigraphic Test Wells (2) |
Gross Production Wells (3) |
|||||||||||||||||||||||||||||||||
2015 | 2014 | 2013 | 2015 | 2014 | 2013 | |||||||||||||||||||||||||||||
Foster Creek |
124 | 165 | 112 | 28 | 63 | 56 | ||||||||||||||||||||||||||||
Christina Lake |
40 | 57 | 74 | 67 | 67 | 35 | ||||||||||||||||||||||||||||
164 | 222 | 186 | 95 | 130 | 91 | |||||||||||||||||||||||||||||
Narrows Lake |
- | 22 | 26 | - | - | - | ||||||||||||||||||||||||||||
Telephone Lake |
- | 45 | 28 | - | - | - | ||||||||||||||||||||||||||||
Grand Rapids |
- | 10 | 3 | 1 | - | - | ||||||||||||||||||||||||||||
Other |
- | 21 | 96 | - | - | - | ||||||||||||||||||||||||||||
164 | 320 | 339 | 96 | 130 | 91 |
(1) | In addition to the drilling activity included within the table, we drilled eight gross service wells in 2015 (2014 three gross service wells; 2013 27 gross service wells). |
(2) | Includes wells drilled using our SkyStratTM drilling rig, which uses a helicopter and a lightweight drilling rig to allow safe stratigraphic well drilling to occur year-round in remote drilling locations. In 2015, we drilled seven wells (2014 14 wells; 2013 24 wells) and commissioned our second SkyStratTM drilling rig. |
(3) | SAGD well pairs are counted as a single producing well. |
Stratigraphic test wells were drilled at Foster Creek and Christina Lake to help identify well pad locations for sustaining wells and near-term expansion phases.
Future Capital Investment
Due to our expectation that low commodity prices will persist for an extended period, we have adopted a more moderate and staged approach to future oil sands expansions. Expanding existing projects and developing emerging projects will depend upon commodity prices, achieving further cost reductions as well as additional fiscal and regulatory certainty.
Cenovus Energy Inc. | 17 | 2015 Managements Discussion and Analysis |
Existing Projects
Foster Creek is currently producing from phases A through F. Capital investment for 2016 is forecast to be between $325 million and $350 million. We plan to continue focusing on sustaining capital related to existing production as well as completing expansion phase G. We expect phase G to add initial design capacity of 30,000 gross barrels per day and first production is anticipated in the third quarter of 2016. Spending related to construction work on phase H was deferred in response to the low commodity price environment, pushing the expected start-up to beyond 2017. Phase H has an initial design capacity of 30,000 gross barrels per day. In December 2014, we received regulatory approval for expansion phase J, a 50,000 gross barrels per day phase.
Christina Lake is producing from phases A through E. Capital investment for 2016 is forecast to be between $350 million and $375 million, focused on sustaining capital related to existing production and expansion phase F. We anticipate adding gross production capacity of 50,000 barrels per day from phase F in the third quarter of 2016. Construction work on phase G was deferred earlier in 2015 in response to the low commodity price environment, pushing the expected start-up to beyond 2017. Phase G has an initial design capacity of 50,000 gross barrels per day. We received regulatory approval in December 2015 for the phase H expansion, a 50,000 gross barrels per day phase.
Capital investment at Narrows Lake in 2016 is forecast to be between $10 million and $20 million, focusing on completing phase A detailed engineering.
Emerging Projects
Capital investment for our new resource plays is forecast to be between $45 million and $55 million in 2016. As of February 2016, further activity in respect of the SAGD pilot at Grand Rapids has been deferred in response to the current low commodity price environment.
DD&A and Exploration Expense
DD&A
We deplete crude oil and natural gas properties on a unit-of-production basis over proved reserves. The unit-of-production rate takes into account expenditures incurred to date, together with future development expenditures required to develop those proved reserves. This rate, calculated at an area level, is then applied to our sales volume to determine DD&A in a given period. We believe that this method of calculating DD&A charges each barrel of crude oil equivalent sold with its proportionate share of the cost of capital invested over the total estimated life of the related asset as represented by proved reserves.
In 2015, Oil Sands DD&A increased $72 million primarily due to higher sales volumes and the impairment of a sulphur recovery facility for $16 million. The average depletion rate was approximately $11.65 per barrel compared with $10.85 per barrel in 2014 as the impact of higher PP&E and future development expenditures were only partially offset by proved reserves additions. Future development costs, which compose approximately 60 percent of the depletable base, increased due to the inclusion of Foster Creek phase J.
Exploration Expense
In 2015, $67 million of previously capitalized E&E costs, related to exploration assets within the Northern Alberta cash-generating unit (CGU), were deemed not to be technically feasible and commercially viable and were recorded as exploration expense. In 2014, $4 million of costs related to the expiry of leases in the Borealis CGU were recorded as exploration expense.
Our Conventional operations include dependable cash flow producing crude oil and natural gas assets in Alberta and Saskatchewan, including a CO2 enhanced oil recovery project in Weyburn, our heavy oil asset at Pelican Lake that uses polymer flood technology and emerging tight oil assets in Alberta. The established assets in this segment are strategically important for their long life reserves, stable operations and diversity of crude oil produced. The cash flow generated in our Conventional operations helps to fund future growth opportunities in our Oil Sands segment while our natural gas production acts as an economic hedge for the natural gas required as a fuel source at both our oil sands and refining operations.
On July 29, 2015, we completed the sale of our royalty interest and mineral fee title lands business, which included approximately 4.8 million gross acres of royalty interest and mineral fee title lands in Alberta, Saskatchewan and Manitoba. A royalty on our working interest production from these fee lands and a GORR on production from our Pelican Lake and Weyburn assets were also included in the sale. We received cash proceeds of approximately $3.3 billion and recorded an after-tax gain of approximately $1.9 billion. Associated third-party royalty interest volumes prior to the divestiture were approximately 6,580 barrels of oil equivalent per day.
Cenovus Energy Inc. | 18 | 2015 Managements Discussion and Analysis |
Additional developments in our Conventional segment in 2015 compared with 2014 include:
| Crude oil production averaging 66,627 barrels per day, decreasing 12 percent, as an increase in production from successful horizontal well performance in southern Alberta was more than offset by expected natural declines, the divestiture of non-core assets in 2014, and the sale of our royalty interest and mineral fee title lands business. Production also declined due to reduced capital investment; |
| Reducing our crude oil operating costs by $124 million or $2.77 per barrel; |
| Generating Operating Cash Flow net of capital investment of $751 million, a decrease of 29 percent; |
| Recording an impairment of $184 million associated with our Northern Alberta CGU due to lower crude oil prices and a slowing down of the development plan; and |
| Recording an exploration expense of $71 million related to previously capitalized exploration assets deemed not to be technically feasible and commercially viable. |
Conventional Crude Oil
Financial and Per-unit Results
2015 | 2014 | 2013 | ||||||||||||||||||||||||||||||||
($ millions, unless otherwise noted) | $ per-unit (1) |
$ per-unit (1) | $ per-unit (1) | |||||||||||||||||||||||||||||||
Gross Sales |
1,239 | 51 | 2,456 | 90 | 2,373 | 85 | ||||||||||||||||||||||||||||
Less: Royalties |
103 | 4 | 217 | 8 | 196 | 7 | ||||||||||||||||||||||||||||
Revenues |
1,136 | 47 | 2,239 | 82 | 2,177 | 78 | ||||||||||||||||||||||||||||
Expenses |
||||||||||||||||||||||||||||||||||
Transportation and Blending |
213 | 9 | 326 | 12 | 305 | 11 | ||||||||||||||||||||||||||||
Operating (2) |
381 | 15 | 505 | 19 | 489 | 18 | ||||||||||||||||||||||||||||
Production and Mineral Taxes |
16 | 1 | 37 | 1 | 32 | 1 | ||||||||||||||||||||||||||||
(Gain) Loss on Risk Management |
(157) | (6) | 4 | - | (43) | (2) | ||||||||||||||||||||||||||||
Operating Cash Flow |
683 | 28 | 1,367 | 50 | 1,394 | 50 | ||||||||||||||||||||||||||||
Capital Investment |
231 | 812 | 1,167 | |||||||||||||||||||||||||||||||
Operating Cash Flow Net of Related Capital Investment |
452 | 555 | 227 |
(1) | Per-unit amounts are calculated on an unblended crude oil basis. |
(2) | For all periods presented, we reclassified employee long-term incentive costs from operating expenses to general and administrative costs. |
Operating Cash Flow Variance
(1) | Revenues include the value of condensate sold as heavy oil blend. Condensate costs are recorded in transportation and blending expense. The crude oil price excludes the impact of condensate purchases. |
Revenues
Pricing
Our average crude oil sales price was $44.63 per barrel in 2015, 45 percent lower than in 2014, consistent with the decline in crude oil benchmark prices.
Production Volumes
(barrels per day) | 2015 | Percent Change |
2014 | Percent Change |
2013 | |||||||||||||||||||||||
Heavy Oil |
34,888 | (12)% | 39,546 | (2)% | 40,245 | |||||||||||||||||||||||
Light and Medium Oil |
30,486 | (12)% | 34,531 | (3)% | 35,467 | |||||||||||||||||||||||
NGLs |
1,253 | 3% | 1,221 | 15% | 1,063 | |||||||||||||||||||||||
66,627 | (12)% | 75,298 | (2)% | 76,775 |
Increased production from successful horizontal well performance in southern Alberta was more than offset by expected natural declines, the divestiture of non-core assets in 2014, and the sale of our royalty interest and
Cenovus Energy Inc. | 19 | 2015 Managements Discussion and Analysis |
mineral fee title lands business. Production also declined due to reduced capital investment. Divested assets contributed 2,555 barrels per day (2014 6,532 barrels per day) to annual production.
Condensate
Revenues represent the total value of blended crude oil sold and include the value of condensate.
Royalties
Royalties decreased $114 million primarily due to lower realized sales prices, partially offset by additional royalty burdens at Pelican Lake, Weyburn and other conventional assets resulting from the sale of our royalty interest and mineral fee title lands business. For 2015, the effective crude oil royalty rate for our Conventional properties was 9.9 percent (2014 10.1 percent).
Crown royalties at Pelican Lake are determined under oil sands royalty calculations. Pelican Lake is a post-payout project, therefore royalties are based on an annualized calculation which uses the greater of: (1) the gross revenues multiplied by the applicable royalty rate (one to nine percent, based on the Canadian dollar equivalent WTI benchmark price); or (2) the net profits of the project multiplied by the applicable royalty rate (25 to 40 percent, based on the Canadian dollar equivalent WTI benchmark price). Gross revenues are a function of sales volumes and realized sales prices. Net profits are a function of sales volumes, realized sales prices and allowed operating and capital costs. The Pelican Lake royalty calculation was based on net profits in 2015 as compared with a calculation based on gross revenues in 2014.
In 2015, production and mineral taxes decreased, consistent with the decline in crude oil prices and due to the sale of our royalty interest and mineral fee title lands business.
Expenses
Transportation and Blending
Transportation and blending costs decreased $113 million. Blending costs declined primarily due to lower condensate prices. In 2015, we recorded a $7 million (2014 $12 million) write-down of our crude oil and condensate inventory to net realizable value as a result of the decline in crude oil prices.
Transportation charges were lower largely due to a decline in sales volumes and a reduction in volumes moved by rail. We transported an average of 597 barrels per day of crude oil by rail (2014 2,706 barrels per day).
Operating
Primary drivers of our operating expenses for 2015 were workforce costs, workover activities, electricity and chemical consumption. Operating expenses declined $124 million or $2.77 per barrel.
The per-unit decline was primarily due to:
| A decline in workover costs and lower repairs and maintenance as a result of focusing on critical activities and achieving operational efficiencies; |
| Lower trucking expenses as we added pipeline infrastructure; |
| Lower chemical costs associated with reduced polymer consumption; and |
| Lower electricity costs as a result of a decrease in consumption due in part to the disposition of non-core assets, and a decline in price. |
These decreases were partially offset by lower production.
Operating Netbacks
(1) | The heavy oil price and transportation and blending costs exclude the cost of purchased condensate which is blended with the heavy oil. On a per-barrel of unblended heavy oil basis, the cost of condensate for our heavy oil properties was $10.94 per barrel (2014 $15.71 per barrel; 2013 $14.60 per barrel). Our blending ratios range from approximately 10 percent to 16 percent. |
(2) | The netbacks do not reflect non-cash write-downs of product inventory in 2015 and 2014. There was no product inventory write-down recorded in 2013. |
Cenovus Energy Inc. | 20 | 2015 Managements Discussion and Analysis |
Risk Management
Risk management activities for 2015 resulted in realized gains of $157 million (2014 realized losses of $4 million), consistent with our contract prices exceeding average benchmark prices.
Conventional Natural Gas
Financial Results
($ millions) | 2015 | 2014 | 2013 | |||||||||||||
Gross Sales |
450 | 744 | 594 | |||||||||||||
Less: Royalties |
11 | 12 | 8 | |||||||||||||
Revenues |
439 | 732 | 586 | |||||||||||||
Expenses |
||||||||||||||||
Transportation and Blending |
17 | 20 | 20 | |||||||||||||
Operating (1) |
175 | 198 | 208 | |||||||||||||
Production and Mineral Taxes |
2 | 9 | 3 | |||||||||||||
(Gain) Loss on Risk Management |
(52) | (5) | (61) | |||||||||||||
Operating Cash Flow |
297 | 510 | 416 | |||||||||||||
Capital Investment |
13 | 28 | 22 | |||||||||||||
Operating Cash Flow Net of Related Capital Investment |
284 | 482 | 394 |
(1) | For all periods presented, we reclassified employee long-term incentive costs from operating expenses to general and administrative costs. |
Operating Cash Flow from natural gas continued to help fund growth opportunities in our Oil Sands segment.
Revenues
Pricing
In 2015, our average natural gas sales price decreased 33 percent to $2.93 per Mcf, consistent with the decline in the AECO benchmark price.
Production
Production decreased nine percent to 422 MMcf per day in 2015 (2014 eight percent to 466 MMcf per day) due to expected natural declines and from the sale of our royalty interest and mineral fee title lands business, which produced 10 MMcf per day in 2015 (2014 20 MMcf per day).
Royalties
Royalties decreased slightly compared with 2014. Reduced royalties as a result of lower prices and production declines were offset by additional royalty burdens due to the sale of our royalty interest and mineral fee title lands business. The average royalty rate in 2015 was 2.7 percent (2014 1.6 percent).
Expenses
Transportation
In 2015, transportation costs decreased as a result of lower production volumes, partially offset by higher pipeline tariffs.
Operating
Primary drivers of our operating expenses were property taxes and lease costs, and workforce. In 2015, operating expenses decreased by $23 million primarily due to lower workforce costs, and repairs and maintenance, partially offset by lower production volumes.
Risk Management
Risk management activities resulted in realized gains of $52 million in 2015 (2014 $5 million), consistent with our contract prices exceeding average benchmark prices.
Conventional Capital Investment
($ millions) | 2015 | 2014 | 2013 | |||||||||||||
Heavy Oil |
63 | 338 | 598 | |||||||||||||
Light and Medium Oil |
168 | 474 | 569 | |||||||||||||
Natural Gas |
13 | 28 | 22 | |||||||||||||
Capital Investment (1) |
244 | 840 | 1,189 |
(1) | Includes expenditures on PP&E and E&E assets. |
Cenovus Energy Inc. | 21 | 2015 Managements Discussion and Analysis |
Capital investment declined in 2015 primarily due to spending reductions on crude oil activities in response to the low commodity price environment. Capital investment in 2015 was primarily related to maintenance capital, spending for our CO2 enhanced oil recovery project at Weyburn and drilling activities at our tight oil projects in southeast Alberta.
Drilling Activity
(net wells, unless otherwise stated) |
2015 | 2014 | 2013 | |||||||||
Crude Oil |
32 | 126 | 212 | |||||||||
Recompletions |
724 | 803 | 751 | |||||||||
Gross Stratigraphic Test Wells |
13 | 30 | 54 | |||||||||
Other (1) |
3 | 40 | 77 |
(1) | Includes dry and abandoned, observation and service wells. |
Drilling activity declined in 2015, reflecting the decision to suspend the majority of our 2015 drilling program in southern Alberta and Saskatchewan as a result of the low commodity price environment. In the second half of the year, modest drilling activities resumed at our tight oil projects in southeast Alberta and at our CO2 enhanced oil recovery project at Weyburn.
Future Capital Investment
Consistent with our expectation that commodity prices will continue to be low for a prolonged period of time, we are taking a more moderate approach to developing our conventional crude oil opportunities. We plan to focus on drilling projects that are considered to be relatively low risk, with short production cycle times and strong expected returns.
Our 2016 crude oil capital investment forecast is between $125 million and $150 million with spending plans mainly focused on maintaining and optimizing current production volumes.
DD&A, Goodwill Impairment and Exploration Expense
DD&A
We deplete crude oil and natural gas properties on a unit-of-production basis over proved reserves. The unit-of-production rate takes into account expenditures incurred to date, together with future development expenditures required to develop those proved reserves. This rate, calculated at an area level, is then applied to our sales volume to determine DD&A in a given period. We believe that this method of calculating DD&A charges each barrel of crude oil equivalent sold with its proportionate share of the cost of capital invested over the total estimated life of the related asset as represented by proved reserves.
Conventional DD&A increased $66 million in 2015 as a decline in sales volumes was more than offset by impairment losses and higher DD&A rates. The average depletion rate increased approximately five percent in 2015 as the impact of lower proved reserves due to the slowdown of our development plans was partially offset by lower PP&E. Future development costs, which compose approximately 30 percent of the depletable base, were consistent with 2014.
In 2015, we recorded an impairment loss of $184 million associated with our Northern Alberta CGU due to lower crude oil prices and a slowing down of our development plan. In 2014, an impairment loss of $52 million was recorded on equipment and in 2013, we recorded a $57 million impairment loss related to our Lower Shaunavon asset sold in July 2013.
Goodwill Impairment
In 2014, we recorded $497 million of goodwill impairment associated with our Pelican Lake property. There was no goodwill impairment in 2015 or 2013.
Exploration Expense
In 2015, $71 million (2014 $82 million) of previously capitalized E&E costs related to exploration assets within the Northern Alberta and Saskatchewan CGUs that were deemed not to be technically feasible and commercially viable and were recorded as exploration expense.
In 2013, $50 million of exploration expense and $64 million of pre-exploration expense was recorded.
We are a 50 percent partner in the Wood River and Borger refineries, which are located in the U.S. Our Refining and Marketing segment positions us to capture the value from crude oil production through to refined products such as diesel, gasoline and jet fuel. Our integrated approach provides a natural economic hedge against widening crude oil price differentials by providing lower feedstock prices to our refineries.
Cenovus Energy Inc. | 22 | 2015 Managements Discussion and Analysis |
Significant developments in our Refining and Marketing segment in 2015 compared with 2014 include:
| Closing the purchase of a crude-by-rail terminal for $75 million, plus adjustments. We commenced operating the terminal in August 2015 and loaded 34 unit trains, including 20 unit trains for third parties; |
| Operating Cash Flow increasing 79 percent to $385 million primarily due to improved margins on the sale of secondary products, weakening of the Canadian dollar relative to the U.S. dollar and an increase in average market crack spreads, partially offset by higher heavy crude oil feedstock costs relative to the WTI benchmark price and higher operating costs; |
| Receiving permit approval for the Wood River debottlenecking project; |
| Successfully completing planned turnarounds at both of our Borger and Wood River refineries; and |
| Exporting crude oil from the U.S. Gulf Coast to broaden market access for our crude oil production. |
Refinery Operations (1)
2015 | 2014 | 2013 | ||||||||||||||
Crude Oil Capacity (2) (Mbbls/d) |
460 | 460 | 457 | |||||||||||||
Crude Oil Runs (Mbbls/d) |
419 | 423 | 442 | |||||||||||||
Heavy Crude Oil |
200 | 199 | 222 | |||||||||||||
Light/Medium |
219 | 224 | 220 | |||||||||||||
Refined Products (Mbbls/d) |
444 | 445 | 463 | |||||||||||||
Gasoline |
228 | 231 | 232 | |||||||||||||
Distillate |
137 | 137 | 144 | |||||||||||||
Other |
79 | 77 | 87 | |||||||||||||
Crude Utilization (percent) |
91 | 92 | 97 |
(1) | Represents 100 percent of the Wood River and Borger refinery operations. |
(2) | The official nameplate capacity, based on 95 percent of the highest average rate achieved over a continuous 30-day period. |
On a 100-percent basis, our refineries have total capacity of approximately 460,000 gross barrels per day of crude oil, excluding NGLs, including processing capability of up to 255,000 gross barrels per day of blended heavy crude oil, and capacity of 45,000 gross barrels per day of NGLs. The ability to refine heavy crude oil demonstrates our ability to economically integrate our heavy crude oil production. The discount of WCS relative to WTI benefits our refining operations due to the feedstock cost advantage provided by processing heavy crude oil.
In 2015, crude oil runs and refined product output were slightly lower compared with 2014. The unplanned outages and planned turnarounds at both of our refineries in 2015 had a similar impact on crude oil runs and refined product output as the outage and turnarounds in 2014.
Our crude utilization represents the percentage of total crude oil processed in our refineries relative to the total capacity. Due to our ability to process a wide slate of crude oils, a feedstock cost advantage is created by processing less expensive crude oil. The amount of heavy crude oil processed, such as WCS and CDB, is dependent on the quality and quantity of available crude oil with the total input slate being optimized at each refinery to maximize economic benefit. The volume of heavy crude oil processed in 2015 increased slightly from 2014.
Financial Results
($ millions) | 2015 | 2014 | 2013 | |||||||||||||
Revenues |
8,805 | 12,658 | 12,706 | |||||||||||||
Purchased Product |
7,709 | 11,767 | 11,004 | |||||||||||||
Gross Margin |
1,096 | 891 | 1,702 | |||||||||||||
Expenses |
||||||||||||||||
Operating (1) |
754 | 703 | 538 | |||||||||||||
(Gain) Loss on Risk Management |
(43 | ) | (27 | ) | 19 | |||||||||||
Operating Cash Flow |
385 | 215 | 1,145 | |||||||||||||
Capital Investment |
248 | 163 | 107 | |||||||||||||
Operating Cash Flow Net of Related Capital Investment |
137 | 52 | 1,038 |
(1) | For all periods presented, we reclassified employee long-term incentive costs from operating expenses to general and administrative costs. |
Gross Margin
Our realized crack spreads are affected by many factors, such as the variety of feedstock crude oil, refinery configuration and the proportion of gasoline, distillate and secondary product output; the time lag between the purchase of crude oil feedstock and the processing of that crude oil through our refineries; and the cost of feedstock. Our feedstock costs are valued on a FIFO accounting basis.
In 2015, the increase in gross margin was primarily due to:
| Improved margins on the sale of our secondary products, such as coke and asphalt, due to lower overall feedstock costs consistent with the decline in WTI; |
| Weakening of the Canadian dollar relative to the U.S. dollar; and |
| An inventory write-down of $15 million related to our refined product inventory, compared with a write-down of $113 million in 2014. |
Cenovus Energy Inc. | 23 | 2015 Managements Discussion and Analysis |
The increase in gross margin was partially offset by higher heavy crude oil feedstock costs relative to WTI, consistent with the narrowing of the WTI-WCS differential.
The weakening of the Canadian dollar relative to the U.S. dollar in 2015, compared with 2014, had a positive impact of approximately $143 million on our refining gross margin.
Our refineries do not blend renewable fuels into the motor fuel products we produce. Consequently, we are obligated to purchase Renewable Identification Numbers (RINs). In 2015, the cost of our RINs was $200 million (2014 $123 million). The increase is consistent with the rise in the ethanol RINs benchmark price.
Revenues and purchased product from third-party crude oil and natural gas sales undertaken by the marketing group in 2015 decreased 36 percent and 38 percent, respectively, from 2014, primarily due to a decline in sales prices, partially offset by an increase in purchased crude oil volumes.
Operating Expense
Primary drivers of operating expenses in 2015 were maintenance, labour, utilities and supplies. Reported operating expenses increased compared with 2014 primarily due to weakening of the Canadian dollar relative to the U.S. dollar, partially offset by a decline in utility costs resulting from lower natural gas prices.
Refining and Marketing Capital Investment
($ millions) |
2015 | 2014 | 2013 | |||||||||||||
Wood River Refinery |
162 | 101 | 64 | |||||||||||||
Borger Refinery |
78 | 61 | 42 | |||||||||||||
Marketing |
8 | 1 | 1 | |||||||||||||
248 | 163 | 107 |
Capital expenditures in 2015 focused on the debottlenecking project at Wood River, capital maintenance, projects improving our refinery reliability and safety, and environmental initiatives. We received permit approval in the first quarter of 2015 for the Wood River debottlenecking project and start-up is anticipated in the third quarter of 2016.
In 2016, we expect to invest between $240 million and $290 million mainly related to the debottlenecking project at Wood River, in addition to maintenance, reliability and environmental initiatives.
DD&A
Refining and the crude-by-rail terminal assets are depreciated on a straight-line basis over the estimated service life of each component of the facilities, which range from 3 to 40 years. The service lives of these assets are reviewed on an annual basis. Refining and Marketing DD&A increased by $35 million in 2015, primarily due to the change in the U.S./Canadian dollar exchange rate.
The Corporate and Eliminations segment includes intersegment eliminations relating to transactions that have been recorded at transfer prices based on current market prices, as well as unrealized intersegment profits in inventory. The gains and losses on risk management represent the unrealized mark-to-market gains and losses related to derivative financial instruments used to mitigate fluctuations in commodity prices, and the unrealized mark-to-market gains and losses on the long-term power purchase contract and interest rate swaps. In 2015, our risk management activities resulted in $195 million of unrealized losses (2014 $596 million of unrealized gains). The Corporate and Eliminations segment also includes Cenovus-wide costs for general and administrative, financing costs and research costs.
($ millions) |
2015 | 2014 | 2013 | |||||||||||||
General and Administrative (1) |
335 | 379 | 365 | |||||||||||||
Finance Costs |
482 | 445 | 529 | |||||||||||||
Interest Income |
(28 | ) | (33 | ) | (96 | ) | ||||||||||
Foreign Exchange (Gain) Loss, Net |
1,036 | 411 | 208 | |||||||||||||
Research Costs |
27 | 15 | 24 | |||||||||||||
(Gain) Loss on Divestiture of Assets |
(2,392 | ) | (156 | ) | 1 | |||||||||||
Other (Income) Loss, Net |
2 | (4 | ) | 2 | ||||||||||||
(538 | ) | 1,057 | 1,033 |
(1) | For all periods presented, we reclassified employee long-term incentive costs from operating expenses to general and administrative costs. |
Expenses
General and Administrative
Primary drivers of our general and administrative expenses in 2015 were workforce, office rent and information technology costs. General and administrative expenses decreased by $87 million primarily due to workforce reductions and lower employee long-term incentive costs driven by the decline in our share price, offset by
Cenovus Energy Inc. | 24 | 2015 Managements Discussion and Analysis |
severance costs of approximately $43 million. Lower discretionary spending also contributed to the reduction of general and administration costs.
Finance Costs
Finance costs include interest expense on our long-term debt, short-term borrowings and U.S. dollar denominated Partnership Contribution Payable, as well as the unwinding of the discount on decommissioning liabilities. Finance costs increased $37 million in 2015 compared with 2014 as weakening of the Canadian dollar relative to the U.S. dollar increased interest incurred on our U.S. dollar denominated debt, partially offset by lower interest incurred on the Partnership Contribution Payable, which was repaid in the first quarter of 2014.
The weighted average interest rate on outstanding debt, excluding the U.S. dollar denominated Partnership Contribution Payable, for 2015 was 5.3 percent (2014 5.0 percent).
Foreign Exchange
($ millions) | 2015 | 2014 | 2013 | |||||||
Unrealized Foreign Exchange (Gain) Loss |
1,097 | 411 | 40 | |||||||
Realized Foreign Exchange (Gain) Loss |
(61) | - |
168 | |||||||
1,036 | 411 | 208 |
The majority of unrealized foreign exchange losses stem from translation of our U.S. dollar denominated debt. The Canadian dollar relative to the U.S. dollar was 16 percent weaker at December 31, 2015 compared with December 31, 2014, resulting in an unrealized loss of $1,097 million.
DD&A
Corporate and Eliminations DD&A includes provisions in respect of corporate assets, such as computer equipment, leasehold improvements and office furniture. Costs associated with corporate assets are depreciated on a straight-line basis over the estimated service life of the assets, which range from three to 25 years. The service lives of these assets are reviewed on an annual basis. DD&A in 2015 was $78 million (2014 $83 million).
Income Tax
($ millions) | 2015 | 2014 | 2013 | |||||||
Current Tax |
||||||||||
Canada |
586 | 94 | 143 | |||||||
United States |
(12) | (2) | 45 | |||||||
Total Current Tax Expense (Recovery) |
574 | 92 | 188 | |||||||
Deferred Tax Expense (Recovery) |
(655) | 359 | 244 | |||||||
(81) | 451 | 432 |
The following table reconciles income taxes calculated at the Canadian statutory rate with the recorded income taxes:
($ millions) | 2015 | 2014 | 2013 | |||||||
Earnings Before Income Tax |
537 | 1,195 | 1,094 | |||||||
Canadian Statutory Rate |
26.1% | 25.2% | 25.2% | |||||||
Expected Income Tax |
140 | 301 | 276 | |||||||
Effect of Taxes Resulting From: |
||||||||||
Foreign Tax Rate Differential |
(41) | (43) | 87 | |||||||
Non-Deductible Stock-Based Compensation |
7 | 13 | 10 | |||||||
Non-Taxable Capital Losses |
137 | 74 | 6 | |||||||
Unrecognized Capital Losses Arising from Unrealized Foreign Exchange |
135 | 50 | 25 | |||||||
Adjustments Arising From Prior Year Tax Filings |
(55) | (16) | (13) | |||||||
Derecognition (Recognition) of Capital Losses |
(149) | (9) | 15 | |||||||
Recognition of U.S. Tax Basis |
(415) | - |
- | |||||||
Change in Statutory Rate |
161 | - |
- | |||||||
Foreign Exchange Gain (Loss) not Included in Net Earnings |
- | (13) | 19 | |||||||
Goodwill Impairment |
- | 125 | - | |||||||
Other |
(1) | (31) | 7 | |||||||
Total Tax |
(81) | 451 | 432 | |||||||
Effective Tax Rate |
(15.1)% | 37.7% | 39.5% |
Cenovus Energy Inc. | 25 | 2015 Managements Discussion and Analysis |
Tax interpretations, regulations and legislation in the various jurisdictions in which Cenovus and its subsidiaries operate are subject to change. We believe that our provision for income taxes is adequate. There are usually a number of tax matters under review and as a result, income taxes are subject to measurement uncertainty. The timing of the recognition of income and deductions for the purpose of current tax expense is determined by relevant tax legislation.
In 2015, current tax increased due to the sale of our royalty interest and mineral fee title lands business and the timing of recognition of partnership income for tax purposes. Of the $574 million of current tax, $391 million is attributed to the sale of the royalty interest and mineral fee title lands business.
We recorded a deferred tax recovery of $415 million arising from an adjustment to the tax basis of our refining assets. The increase in tax basis was a result of our partner recognizing a taxable gain on its interest in WRB Refining LP (WRB) which, due to an election filed with the U.S. tax authorities, was added to the tax basis of WRBs assets. Additionally, the deferred tax recovery was due to the timing of recognition of partnership income, unrealized risk management losses, reversal of other temporary differences and current year operating losses. This was partially offset by a one-time charge of approximately $161 million from the revaluation of the deferred tax liability due to an increase in the Alberta corporate income tax rate from 10 percent to 12 percent on July 1, 2015.
Our effective tax rate is a function of the relationship between total tax expense and the amount of earnings before income taxes. The effective tax rate differs from the statutory tax rate as it reflects higher U.S. tax rates, permanent differences, adjustments for changes in tax rates and other tax legislation, variations in the estimate of reserves and differences between the provision and the actual amounts subsequently reported on the tax returns.
Our effective tax rate for 2015 differs from the statutory rate due to an increase in tax basis of our U.S. assets, and the recognition of the benefit of capital losses, partially offset by non-deductible unrealized foreign exchange losses and a one-time deferred tax expense arising from the Alberta corporate income tax rate increase.
Our quarterly results over the last eight quarters were impacted primarily by rising crude oil production volumes and fluctuations in commodity prices. Crude oil production in the fourth quarter of 2015 was six percent higher than in the fourth quarter of 2013, while and natural gas production decreased 18 percent from the fourth quarter of 2013. Our average crude oil and natural gas prices in the fourth quarter of 2015 were 53 percent and 13 percent lower compared with the fourth quarter of 2013.
($ millions, except per share amounts or where otherwise indicated) |
2015 | 2014 | 2013 | |||||||||||||||||||||||||||||||||
Q4 | Q3 | Q2 | Q1 | Q4 | Q3 | Q2 | Q1 | Q4 | ||||||||||||||||||||||||||||
Production Volumes |
||||||||||||||||||||||||||||||||||||
Crude Oil (bbls/d) |
199,556 | 210,422 | 199,954 | 218,020 | 216,177 | 199,089 | 201,688 | 196,854 | 188,743 | |||||||||||||||||||||||||||
Natural Gas (MMcf/d) |
424 | 430 | 450 | 462 | 479 | 489 | 507 | 476 | 514 | |||||||||||||||||||||||||||
Refinery Operations |
||||||||||||||||||||||||||||||||||||
Crude Oil Runs (Mbbls/d) |
405 | 394 | 441 | 439 | 420 | 407 | 466 | 400 | 447 | |||||||||||||||||||||||||||
Refined Products (Mbbls/d) |
430 | 414 | 462 | 469 | 442 | 429 | 489 | 420 | 469 | |||||||||||||||||||||||||||
Revenues |
2,924 | 3,273 | 3,726 | 3,141 | 4,238 | 4,970 | 5,422 | 5,012 | 4,747 | |||||||||||||||||||||||||||
Operating Cash Flow (1) (2) |
357 | 602 | 932 | 548 | 537 | 1,156 | 1,305 | 1,181 | 976 | |||||||||||||||||||||||||||
Cash Flow (1) |
275 | 444 | 477 | 495 | 401 | 985 | 1,189 | 904 | 835 | |||||||||||||||||||||||||||
Per Share Diluted |
0.33 | 0.53 | 0.58 | 0.64 | 0.53 | 1.30 | 1.57 | 1.19 | 1.10 | |||||||||||||||||||||||||||
Operating Earnings (Loss) (1) |
(438 | ) | (28 | ) | 151 | (88 | ) | (590 | ) | 372 | 473 | 378 | 212 | |||||||||||||||||||||||
Per Share Diluted |
(0.53 | ) | (0.03 | ) | 0.18 | (0.11 | ) | (0.78 | ) | 0.49 | 0.62 | 0.50 | 0.28 | |||||||||||||||||||||||
Net Earnings (Loss) |
(641 | ) | 1,801 | 126 | (668 | ) | (472 | ) | 354 | 615 | 247 | (58 | ) | |||||||||||||||||||||||
Per Share Basic |
(0.77 | ) | 2.16 | 0.15 | (0.86 | ) | (0.62 | ) | 0.47 | 0.81 | 0.33 | (0.08 | ) | |||||||||||||||||||||||
Per Share Diluted |
(0.77 | ) | 2.16 | 0.15 | (0.86 | ) | (0.62 | ) | 0.47 | 0.81 | 0.33 | (0.08 | ) | |||||||||||||||||||||||
Capital Investment (3) |
428 | 400 | 357 | 529 | 786 | 750 | 686 | 829 | 898 | |||||||||||||||||||||||||||
Dividends |
||||||||||||||||||||||||||||||||||||
Cash Dividends |
132 | 133 | 125 | 138 | 201 | 201 | 201 | 202 | 183 | |||||||||||||||||||||||||||
In Shares from Treasury |
- | - | 98 | 84 | - | - | - | - | - | |||||||||||||||||||||||||||
Per Share |
0.16 | 0.16 | 0.2662 | 0.2662 | 0.2662 | 0.2662 | 0.2662 | 0.2662 | 0.242 |
(1) | Non-GAAP measure defined in this MD&A. |
(2) | For all periods presented, we reclassified employee long-term incentive costs from operating expenses to general and administrative costs. There were no changes to Cash Flow, Operating Earnings or Net Earnings. |
(3) | Includes expenditures on PP&E and E&E assets. |
Cenovus Energy Inc. | 26 | 2015 Managements Discussion and Analysis |
A substantial downward shift in the commodity price environment occurred late in 2014 and continued throughout 2015. Declining crude oil and refining benchmark prices impacted our fourth quarter financial results. Average Brent and WTI benchmark prices decreased 42 percent in the fourth quarter of 2015 compared with 2014, while the U.S. dollar average WCS price decreased 53 percent.
Fourth Quarter 2015 Results as Compared with the Fourth Quarter 2014
Production Volumes
Total crude oil production declined eight percent primarily due to expected natural declines, the sale of our royalty interest and mineral fee title lands business, and lower production at Foster Creek. Fourth quarter production was lower compared with 2014. Improved wellbore conformance accelerated production from more mature wells, resulting in faster declines from these wells. To preserve capital, we chose in 2015 to defer some planned well pads, which combined with the faster declines, contributed to lower fourth quarter volumes. In addition, while well downtime at Foster Creek was within expected ranges for 2015, a higher than average number of wells were down for servicing in the second half of the year, which further impacted production.
These reductions were partially offset by higher production at Christina Lake and from successful horizontal well performance in southern Alberta. Third-party royalty interest volumes prior to the divestiture in the third quarter were approximately 6,580 barrels of oil equivalent per day.
Natural gas production in the fourth quarter of 2015 decreased 11 percent due to expected natural declines. We continued to focus capital investment on high rate of return projects and directed the majority of our total capital investment to our crude oil properties.
Refinery Operations
Crude oil runs decreased and refined product output decreased as the planned turnaround at Wood River in 2015 was larger in scale than in 2014. In addition, our Wood River refinery experienced unplanned outages in the fourth quarter of 2015.
Revenue
Revenues decreased $1,314 million or 31 percent primarily due to:
| A decline in Refining and Marketing revenues of $743 million largely due a decrease in refined product prices, consistent with a 37 percent decline in average refined product benchmark prices, and lower refined product output; |
| Crude oil and natural gas sales volumes decreasing two percent and 11 percent, respectively; |
| Our average crude oil sales price (excluding financial hedging) decreasing 50 percent to $27.63 per barrel; and |
| A decline in natural gas sales prices (excluding financial hedging) of 29 percent to $2.78 per Mcf. |
The decreases to revenues were partially offset by:
| Crude oil royalties decreasing $68 million; and |
| An increase in condensate volumes used for blending with our bitumen and heavy oil production. |
Operating Cash Flow
Operating Cash Flow decreased $180 million, or 34 percent, in the three months ended December 31, 2015 compared with 2014. Upstream Operating Cash Flow decreased 54 percent due to lower crude oil and natural gas sales prices, and lower crude oil and natural gas sales volumes, partially offset by higher realized risk management gains and lower royalties due to a decrease in crude oil sales prices.
Refining and Marketing Operating Cash Flow increased by 88 percent to a loss of $40 million. The increase was due to improved margins on the sale of secondary products, weakening of the Canadian dollar relative to the U.S. dollar, an increase in average market crack spreads and lower refined product inventory impairments, partially offset by lower refined product output and higher operating costs.
Cash Flow
Cash Flow decreased $126 million or 31 percent in the fourth quarter of 2015 compared with 2014, primarily due to lower Operating Cash Flow, as discussed above, and an increase in our general and administrative expenses mainly driven by severance costs related to the previously announced workforce reductions, partially offset by a higher current income tax recovery.
Cenovus Energy Inc. | 27 | 2015 Managements Discussion and Analysis |
Operating Earnings (Loss)
In the fourth quarter of 2015, our Operating Loss was $438 million compared with a loss of $590 million in the same period in 2014. The improvement was primarily due to no goodwill impairment in 2015 compared with a goodwill impairment of $497 million in 2014 and a higher income tax recovery, partially offset by lower Cash Flow and an increase in DD&A and exploration expense.
Net Earnings (Loss)
In 2015, our Net Loss included unrealized risk management losses of $26 million and non-operating foreign exchange losses of $212 million in addition to the Operating Loss discussed above. In 2014, our Net Loss was smaller due to unrealized risk management gains of $416 million, partially offset by a larger Operating Loss and non-operating foreign exchange losses of $186 million.
Capital Investment
Capital investment in the fourth quarter of 2015 was $428 million, a 46 percent decrease from the same period in 2014 primarily due to lower spending in our Oil Sands and Conventional segments. Capital investment was reduced with the intent of conserving cash and maintaining the strength of our balance sheet in light of the low commodity price environment.
OIL AND GAS RESERVES AND RESOURCES
We retain independent qualified reserves evaluators (IQREs) to evaluate and prepare reports on 100 percent of our bitumen, heavy oil, light and medium oil, NGLs, natural gas and coal bed methane (CBM) reserves and 100 percent of our bitumen contingent and prospective resources producible with established technology.
The sale of our royalty interest and mineral fee title lands business had a minimal effect on our reserves, before royalties. However, our proved and proved plus probable reserves, after royalties, decreased by 27 MMBOE and 39 MMBOE, respectively.
Additional developments in 2015 compared with 2014 include:
| Proved bitumen reserves increasing 11 percent due to Christina Lake proved reserves additions of 234 million barrels from improved reservoir performance and regulatory approval of the Kirby East area expansion converting probable reserves to proved reserves; |
| Proved plus probable bitumen reserves remaining constant due to improved reservoir performance at Foster Creek and Christina Lake offsetting production; |
| Heavy oil proved reserves and proved plus probable reserves declining 15 percent and 21 percent, respectively. The decrease was due to the deferral of drilling at Pelican Lake, the impact of low crude oil prices and the loss of undeveloped reserves at Elk Point due to poor economics; |
| Light and medium oil and NGLs proved reserves decreasing eight percent and proved plus probable reserves decreasing seven percent as production exceeded additions; |
| Natural gas proved reserves declining nine percent and proved plus probable reserves decreasing 10 percent as additions and improved performance were more than offset by reductions due to production; and |
| Bitumen best estimate economic contingent resources remaining flat at 9.3 billion barrels and bitumen best estimate prospective resources decreasing slightly to 7.4 billion barrels. Factors impacting the results include: |
¡ | Reduced stratigraphic drilling yielding negligible contingent resources revisions; and |
¡ | Minor mapping changes plus small lease expiries slightly reducing prospective resources. |
The reserves and resources data that follows is presented as at December 31, 2015 using McDaniel & Associates Consultants Ltd.s (McDaniels) January 1, 2016 forecast prices and inflation. Comparative information as at December 31, 2014 uses McDaniels January 1, 2015 forecast prices and inflation.
Reserves
As at December 31, | Bitumen (MMbbls) |
Heavy Oil (MMbbls) |
Light and Medium Oil & NGLs (MMbbls) |
Natural Gas & CBM (Bcf) |
||||||||||||||||||||||||||||||||||
(before royalties) | 2015 | 2014 | 2015 | 2014 | 2015 | 2014 | 2015 | 2014 | ||||||||||||||||||||||||||||||
Proved |
2,183 | 1,970 | 133 | 156 | 110 | 120 | 721 | 796 | ||||||||||||||||||||||||||||||
Probable |
1,115 | 1,330 | 87 | 123 | 44 | 46 | 232 | 260 | ||||||||||||||||||||||||||||||
Proved plus Probable |
3,298 | 3,300 | 220 | 279 | 154 | 166 | 953 | 1,056 | ||||||||||||||||||||||||||||||
Cenovus Energy Inc. | 28 | 2015 Managements Discussion and Analysis |
Reconciliation of Proved Reserves
(before royalties) | Bitumen (MMbbls) |
Heavy Oil (MMbbls) |
Light & Oil & NGLs (MMbbls) |
Natural Gas & CBM (Bcf) |
||||||||||||||||||
December 31, 2014 |
1,970 | 156 | 120 | 796 | ||||||||||||||||||
Extensions and Improved Recovery |
188 | - | 1 | 8 | ||||||||||||||||||
Technical Revisions |
76 | (10) | 1 | 79 | ||||||||||||||||||
Economic Factors |
- | - | (1) | (1) | ||||||||||||||||||
Production (1) |
(51) | (13) | (11) | (161) | ||||||||||||||||||
December 31, 2015 |
2,183 | 133 | 110 | 721 | ||||||||||||||||||
Year Over Year Change |
213 | (23) | (10) | (75) | ||||||||||||||||||
11% | (15)% | (8)% | (9)% | |||||||||||||||||||
(1) Production includes the natural gas used as a fuel source in our oil sands operations and excludes royalty interest production. |
| |||||||||||||||||||||
Reconciliation of Probable Reserves
|
| |||||||||||||||||||||
(before royalties) | Bitumen (MMbbls) |
Heavy Oil (MMbbls) |
Light & Oil & NGLs (MMbbls) |
Natural Gas & CBM (Bcf) |
||||||||||||||||||
December 31, 2014 |
1,330 | 123 | 46 | 260 | ||||||||||||||||||
Extensions and Improved Recovery |
- | - | 1 | 7 | ||||||||||||||||||
Technical Revisions |
(215) | (36) | (4) | (36) | ||||||||||||||||||
Economic Factors |
- | - | 1 | 1 | ||||||||||||||||||
December 31, 2015 |
1,115 | 87 | 44 | 232 | ||||||||||||||||||
Year Over Year Change |
(215) | (36) | (2) | (28) | ||||||||||||||||||
(16)% | (29)% | (4)% | (11)% |
Economic Contingent Resources and Prospective Resources
As at December 31, | Bitumen | |||||||
(billions of barrels, before royalties) | 2015 | 2014 | ||||||
Economic Contingent Resources (1) |
||||||||
Best Estimate |
9.3 | 9.3 | ||||||
Prospective Resources (1) (2) |
||||||||
Best Estimate |
7.4 | 7.5 |
(1) | See Oil and Gas Information in the Advisory for definitions of contingent resources, economic contingent resources, prospective resources and best estimates. There is no certainty that it will be commercially viable to produce any portion of the contingent resources. |
(2) | There is uncertainty that any portion of the prospective resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the prospective resources. Prospective resources are not screened for economic viability. |
Additional information with respect to the evaluation and reporting of our reserves in accordance with National Instrument 51-101, Standards of Disclosure for Oil and Gas Activities (NI 51-101), and material risks and uncertainties associated with estimates of reserves and contingent and prospective resources is contained in our AIF for the year ended December 31, 2015. Further information with respect to contingent and prospective resources including project descriptions, significant factors relevant to the resource estimates, and contingencies which prevent the classification of contingent resources as reserves is contained in our supplemental Statement of Contingent and Prospective Resources for the year ended December 31, 2015 (Resources Statement). Both our AIF and Resources Statement are available on SEDAR at sedar.com, EDGAR at sec.gov and on our website at cenovus.com.
LIQUIDITY AND CAPITAL RESOURCES
($ millions) | 2015 | 2014 | 2013 | |||||||||||||
Net Cash From (Used In) |
||||||||||||||||
Operating Activities |
1,474 | 3,526 | 3,539 | |||||||||||||
Investing Activities |
888 | (4,350 | ) | (1,519 | ) | |||||||||||
Net Cash Provided (Used) Before Financing Activities |
2,362 | (824 | ) | 2,020 | ||||||||||||
Financing Activities |
894 | (797 | ) | (726 | ) | |||||||||||
Foreign Exchange Gain (Loss) on Cash and Cash Equivalents Held in Foreign Currency |
(34 | ) | 52 | (2 | ) | |||||||||||
Increase (Decrease) in Cash and Cash Equivalents |
3,222 | (1,569 | ) | 1,292 | ||||||||||||
As at December 31, | 2015 | 2014 | 2013 | |||||||||||||
Cash and Cash Equivalents |
4,105 | 883 | 2,452 | |||||||||||||
Committed and Undrawn Credit Facilities |
4,000 | 3,000 | 3,000 |
Cenovus Energy Inc. | 29 | 2015 Managements Discussion and Analysis |
Operating Activities
Cash from operating activities decreased in 2015 mainly due to lower Cash Flow, as discussed in the Financial Results section of this MD&A. Excluding risk management assets and liabilities, working capital was $4,337 million at December 31, 2015 compared with $772 million at December 31, 2014. Working capital increased due to cash proceeds received on the sale of our royalty interest and mineral fee title lands business in July of 2015 and the common share issuance in the first quarter of 2015.
We anticipate that we will continue to meet our payment obligations as they come due.
Investing Activities
Cash from investing activities in 2015 was primarily due to the divestiture of our royalty interest and mineral fee title lands business in 2015. In 2014, cash used by investing activities related to the repayment of the US$1.4 billion Partnership Contribution Payable. Lower capital expenditures in 2015 also contributed to the increase in cash from investing activities.
Financing Activities
Cash provided by financing activities increased in 2015 primarily due to net proceeds from our common share issuance and cash savings from our DRIP. We issued 67.5 million common shares at a price of $22.25 per share for net proceeds of $1.4 billion in the first quarter of 2015. We plan to use the net proceeds to partially fund our capital expenditure program for 2016 and for general corporate purposes.
In 2015, we paid dividends of $0.8524 per share or $710 million, of which $528 million was paid in cash and $182 million was reinvested in common shares through our DRIP (2014 $1.0648 per share or $805 million paid in cash). The declaration of dividends is at the sole discretion of the Board and is considered quarterly.
Our long-term debt at December 31, 2015 was $6,525 million (December 31, 2014 $5,458 million) with no principal payments due until October 2019 (US$1.3 billion). The principal amount of long-term debt outstanding in U.S. dollars has remained unchanged since August 2012. The $1,067 million increase in long-term debt is due to weakening of the Canadian dollar relative to the U.S. dollar.
As at December 31, 2015, we were in compliance with all of the terms of our debt agreements.
Available Sources of Liquidity
We expect cash flow from our crude oil, natural gas and refining operations to fund a portion of our cash requirements. Any potential shortfalls may be required to be funded through prudent use of our balance sheet capacity, management of our asset portfolio and other corporate and financial opportunities that may be available to us.
The following sources of liquidity are available at December 31, 2015:
($ millions) | Amount | Term | ||||||||
Cash and Cash Equivalents |
4,105 | Not applicable | ||||||||
Committed Credit Facility |
1,000 | November 2017 | ||||||||
Committed Credit Facility |
3,000 | November 2019 | ||||||||
U.S. Base Shelf Prospectus (1) |
US$ | 2,000 | July 2016 | |||||||
Canadian Base Shelf Prospectus (1) |
1,500 | July 2016 |
(1) | Availability is subject to market conditions. |
Committed Credit Facility
In 2015, Cenovus renegotiated its existing $3.0 billion committed credit facility, extending the maturity date to November 30, 2019. In addition, a new $1.0 billion tranche was established under the same facility, maturing on November 30, 2017. As at December 31, 2015, we had $4.0 billion available on our committed credit facility.
Under the committed credit facility, Cenovus is required to maintain a debt to capitalization ratio not to exceed 65 percent; we are well below this limit.
U.S. and Canadian Base Shelf Prospectuses
On June 24, 2014, we filed a U.S. base shelf prospectus for unsecured notes in the amount of US$2.0 billion, which replaced the U.S. base shelf prospectus dated June 6, 2012, as amended May 9, 2013. The U.S. base shelf prospectus allows for the issuance of debt securities in U.S. dollars or other currencies from time to time in one or more offerings. Terms of the notes, including, but not limited to, interest at either fixed or floating rates and maturity dates will be determined at the date of issue.
On June 25, 2014, we filed a Canadian base shelf prospectus for unsecured medium term notes in the amount of $1.5 billion, which replaced the Canadian base shelf prospectus dated May 24, 2012. The Canadian base shelf prospectus allows for the issuance of medium term notes in Canadian dollars or other currencies from time to time in one or more offerings. Terms of the notes, including, but not limited to, interest at either fixed or floating rates and maturity dates will be determined at the date of issue.
Cenovus Energy Inc. | 30 | 2015 Managements Discussion and Analysis |
As at December 31, 2015, no notes were issued under the existing U.S. or Canadian base shelf prospectuses.
It is our intention to file a new prospectus prior to the maturity of the existing prospectuses.
Financial Metrics
We monitor our capital structure and financing requirements using, among other things, non-GAAP financial metrics consisting of Debt to Capitalization and Debt to Adjusted EBITDA. We define our non-GAAP measure of Debt as short-term borrowings and the current and long-term portions of long-term debt. We define Capitalization as Debt plus Shareholders Equity. We define Adjusted EBITDA as earnings before finance costs, interest income, income tax expense, DD&A, goodwill and asset impairments, unrealized gains (losses) on risk management, foreign exchange gains (losses), gains (losses) on divestiture of assets and other income (loss), net, calculated on a trailing twelve-month basis. These metrics are used to steward our overall debt position and as measures of our overall financial strength.
Over the long-term, we target a Debt to Capitalization ratio of between 30 percent to 40 percent and a Debt to Adjusted EBITDA of between 1.0 times to 2.0 times. At different points within the economic cycle, we expect these ratios may periodically be outside of the target range.
Debt to Capitalization remained consistent as higher debt balances from the weakening of the Canadian dollar relative to the U.S. dollar were offset by the increase in Shareholders Equity as a result of the common share issuance. Debt to Adjusted EBITDA increased from higher debt balances due to foreign exchange and lower Adjusted EBITDA primarily due to a decline in Cash Flow as a result of low commodity prices.
Debt to Capitalization and Net Debt to Capitalization are calculated as follows:
As at December 31, | 2015 | 2014 | 2013 | |||||||||||||
Debt |
6,525 | 5,458 | 4,997 | |||||||||||||
Shareholders Equity |
12,391 | 10,186 | 9,946 | |||||||||||||
Capitalization |
18,916 | 15,644 | 14,943 | |||||||||||||
Debt to Capitalization |
34% | 35% | 33% | |||||||||||||
Net Debt (1) |
2,420 | 4,575 | 4,070 | |||||||||||||
Shareholders Equity |
12,391 | 10,186 | 9,946 | |||||||||||||
Capitalization |
14,811 | 14,761 | 14,016 | |||||||||||||
Net Debt to Capitalization |
16% | 31% | 29% |
(1) | Net Debt is defined as Debt and the current and long-term portions of the Partnership Contribution Payable, net of cash and cash equivalents. |
The following is a reconciliation of Adjusted EBITDA, and the calculations of Debt to Adjusted EBITDA and Net Debt to Adjusted EBITDA:
As at December 31, | 2015 | 2014 | 2013 | |||||||||||||
Debt |
6,525 | 5,458 | 4,997 | |||||||||||||
Net Debt (1) |
2,420 | 4,575 | 4,070 | |||||||||||||
Adjusted EBITDA |
||||||||||||||||
Net Earnings |
618 | 744 | 662 | |||||||||||||
Add (Deduct): |
||||||||||||||||
Finance Costs |
482 | 445 | 529 | |||||||||||||
Interest Income |
(28) | (33) | (96) | |||||||||||||
Income Tax Expense |
(81) | 451 | 432 | |||||||||||||
DD&A |
2,114 | 1,946 | 1,833 | |||||||||||||
Goodwill Impairment |
- | 497 | - | |||||||||||||
E&E Impairment |
138 | 86 | 50 | |||||||||||||
Unrealized (Gain) Loss on Risk Management |
195 | (596) | 415 | |||||||||||||
Foreign Exchange (Gain) Loss, Net |
1,036 | 411 | 208 | |||||||||||||
(Gain) Loss on Divestiture of Assets |
(2,392) | (156) | 1 | |||||||||||||
Other (Income) Loss, Net |
2 | (4) | 2 | |||||||||||||
2,084 | 3,791 | 4,036 | ||||||||||||||
Debt to Adjusted EBITDA |
3.1x | 1.4x | 1.2x | |||||||||||||
Net Debt to Adjusted EBITDA |
1.2x | 1.2x | 1.0x |
(1) | Net Debt is defined as Debt and the current and long-term portions of the Partnership Contribution Payable, net of cash and cash equivalents. |
Additional information regarding our financial metrics and capital structure can be found in the notes to the Consolidated Financial Statements.
Cenovus Energy Inc. | 31 | 2015 Managements Discussion and Analysis |
Share Capital and Stock-Based Compensation Plans
As at December 31, 2015, there were approximately 833 million common shares outstanding (December 31, 2014 757 million common shares). Cenovus issued 76.2 million common shares in 2015, including 8.7 million shares issued under the DRIP and 67.5 million shares issued related to the common share issuance in the first quarter of 2015.
The DRIP permits shareholders to reinvest their dividends into additional common shares. At the discretion of Cenovus, the additional common shares may be issued from treasury or purchased on the market. In the first half of 2015, participants in our DRIP were issued shares from treasury at a three percent discount to the average market price, as defined in the DRIP; this resulted in cash savings of $177 million. For the second half of the year, common shares acquired by the DRIP were purchased on the open market. Refer to cenovus.com for more details.
As part of our long-term incentive program, Cenovus has an employee Stock Option Plan as well as Performance Share Unit (PSU) Plan, a Restricted Share Unit (RSU) Plan and two Deferred Share Unit (DSU) Plans. Refer to Note 27 of the Consolidated Financial Statements for more details on our Stock Option Plan and our PSU, RSU and DSU Plans.
As at January 31, 2016 | Units Outstanding (thousands) |
Units Exercisable (thousands) |
||||||||
Common Shares |
833,290 | N/A | ||||||||
Stock Options |
43,660 | 25,892 | ||||||||
Other Stock-Based Compensation Plans |
10,257 | 1,488 |
Contractual Obligations and Commitments
We have entered into various commitments in the normal course of operations primarily related to demand charges on firm transportation agreements and operating leases on buildings. In addition, we have commitments related to our risk management program and an obligation to fund our defined benefit pension and other post-employment benefit plans.
The below contractual obligations have been grouped as operating, investing and financing, relating to the type of cash outflow that will arise:
Expected Payment Date | ||||||||||||||||||||||||||||||||||||||||
($ millions) | 2016 | 2017 | 2018 | 2019 | 2020 | Thereafter | Total | |||||||||||||||||||||||||||||||||
Operating |
||||||||||||||||||||||||||||||||||||||||
Transportation and Storage (1) |
702 | 715 | 780 | 774 | 901 | 23,537 | 27,409 | |||||||||||||||||||||||||||||||||
Operating Leases (Building Leases) |
116 | 120 | 156 | 153 | 151 | 2,647 | 3,343 | |||||||||||||||||||||||||||||||||
Product Purchases |
84 | 3 | - | - | - | - | 87 | |||||||||||||||||||||||||||||||||
Other Long-term Commitments |
45 | 31 | 24 | 26 | 15 | 125 | 266 | |||||||||||||||||||||||||||||||||
Interest on Long-term Debt |
349 | 349 | 349 | 349 | 247 | 4,193 | 5,836 | |||||||||||||||||||||||||||||||||
Decommissioning Liabilities |
34 | 28 | 28 | 30 | 36 | 6,509 | 6,665 | |||||||||||||||||||||||||||||||||
Total Operating |
1,330 | 1,246 | 1,337 | 1,332 | 1,350 | 37,011 | 43,606 | |||||||||||||||||||||||||||||||||
Investing |
||||||||||||||||||||||||||||||||||||||||
Capital Commitments |
61 | 14 | 4 | - | - | - | 79 | |||||||||||||||||||||||||||||||||
Total Investing |
61 | 14 | 4 | - | - | - | 79 | |||||||||||||||||||||||||||||||||
Financing |
||||||||||||||||||||||||||||||||||||||||
Long-term Debt (principal only) |
- | - | - | 1,799 | - | 4,775 | 6,574 | |||||||||||||||||||||||||||||||||
Total Financing |
- | - | - | 1,799 | - | 4,775 | 6,574 | |||||||||||||||||||||||||||||||||
Total Payments (2) |
1,391 | 1,260 | 1,341 | 3,131 | 1,350 | 41,786 | 50,259 | |||||||||||||||||||||||||||||||||
Fixed Price Product Sales |
55 | 3 | - | - | - | - | 58 |
(1) | Certain transportation commitments included are subject to regulatory approval. |
(2) | Contracts on behalf of FCCL Partnership (FCCL) and WRB are reflected at our 50 percent interest. |
As operator of Foster Creek, Christina Lake and Narrows Lake, we are responsible for the field operations, marketing and transportation of 100 percent of the production from these assets. We have entered into various commitments in the normal course of operations primarily related to demand charges on firm transportation agreements. In addition, we have commitments related to our risk management program and an obligation to fund our defined benefit pension and other post-employment benefit plans. For further information, see the notes to the Consolidated Financial Statements.
Commitments for various firm pipeline transportation agreements were $27 billion, consistent with 2014. Reduced obligations from changes to TransCanadas proposed Energy East pipeline were offset by increases to our U.S. dollar commitments due to the weakening of the Canadian dollar relative to the U.S. dollar, and higher costs and tolls on existing commitments.
Cenovus Energy Inc. | 32 | 2015 Managements Discussion and Analysis |
We continue to focus on near- and mid-term strategies to broaden market access for our crude oil production, as illustrated by our purchase of a crude-by-rail terminal and exporting crude oil from the U.S. Gulf Coast. We continue to support proposed new pipeline projects that would connect us to new markets in the U.S. and globally, moving our crude oil production to market by rail, assessing options to maximize the value of our crude oil by offering a wider range of products, including existing dilbit blends, under-blended bitumen or dry bitumen, and potential expansions of our refining capacity as our production grows.
As at December 31, 2015, Cenovus remained a party to long-term, fixed price, physical contracts for natural gas with a current delivery of approximately 29 MMcf per day, with varying terms and volumes through 2017. The total volume to be delivered within the terms of these contracts is 11 Bcf of natural gas, at a weighted average price of $4.94 per Mcf.
In the normal course of business, we also lease office space for staff who support field operations and for corporate purposes.
Legal Proceedings
We are involved in a limited number of legal claims associated with the normal course of operations and we believe we have made adequate provisions for such claims. There are no individually or collectively significant claims.
Related Party Transactions
Cenovus did not enter into any related party transactions during the years ended December 31, 2015 or 2014, except for our key management compensation. A summary of key management compensation can be found in the notes to the Consolidated Financial Statements.
Cenovus is exposed to a number of risks through the pursuit of our strategic objectives. Some of these risks impact the oil and gas industry as a whole and others are unique to our operations. Our Enterprise Risk Management (ERM) program drives the identification, measurement, prioritization, and management of risk across Cenovus.
Risk Governance
The ERM Policy, approved by our Board, outlines our risk management principles and expectations, as well as the roles and responsibilities of all staff. Building on the ERM Policy, we have established Risk Management Practices, a Risk Management Framework and Risk Assessment Tools. Our Risk Management Framework contains the key attributes recommended by the International Standards Organization (ISO) in its ISO 31000 Risk Management Principles and Guidelines. The results of our ERM program are documented in an Annual Risk Report presented to the Board as well as through quarterly updates.
Risk Assessment
All risks are assessed for their potential impact on the achievement of Cenovuss strategic objectives as well as their likelihood of occurring. Risks are analyzed through the use of a Risk Matrix and other standardized risk assessment tools. |
![]() |
Using a Risk Matrix, each risk is classified on a continuum ranging from Low to Extreme. Risks are first evaluated on an inherent basis, without considering the presence of controls or mitigating measures. Risks are then re-evaluated based on their residual risk ranking, reflecting the exposure that remains after implemented mitigation and control measures are considered.
Management determines if additional risk treatment is required based on the residual risk ranking. There are prescribed actions for escalating and communicating risk to the right decision makers.
Significant Risk Factors
The following discussion describes the financial, operations and regulatory risks relating to Cenovus and our operations. A description of the risk factors and uncertainties can be found in the Advisory and a full discussion of the material risk factors affecting Cenovus can be found in our AIF for the year ended December 31, 2015.
Financial Risk
Financial risk is the risk of loss or lost opportunity resulting from financial management and market conditions. From time to time, Management may enter into contracts to mitigate risk associated with fluctuations of commodity prices, interest rates and foreign exchange rates.
Cenovus Energy Inc. | 33 | 2015 Managements Discussion and Analysis |
Commodity Prices
Fluctuations in commodity prices and refined product prices impacts our financial condition, results of operations, cash flows, growth, access to capital and cost of borrowing.
Crude oil and natural gas prices are impacted by a number of factors including global and regional supply and demand and economic conditions, the actions of OPEC, government regulation, political stability, transportation constraints, weather conditions and availability of alternative fuels, all of which are beyond our control and can result in a high degree of price volatility. Changing prices will affect the revenues generated by the sale of our production. Our financial performance is also affected by price differentials since our upstream production differs in quality and location from underlying benchmark commodity prices quoted on financial exchanges.
Commodity prices began to decline in the fourth quarter of 2014 and have remained low, resulting in an impairment to the carrying value of some of our assets. If crude oil and natural gas prices continue to decline significantly and remain at low levels for an extended period of time, future capital spending could be reduced causing projects to be impaired, delayed or cancelled, and production could be curtailed or suspended, among other impacts.
Refined product prices are affected by several factors including global supply and demand for refined products, weather conditions, and planned and unplanned refinery maintenance, all of which are beyond our control and can result in a high degree of price volatility. The financial performance of our refining operations is also impacted by margin volatility due to fluctuations in the supply and demand for refined products, crude oil costs and seasonal factors when production changes to match seasonal demand.
We partially mitigate our exposure to commodity price risk through the integration of our business, financial instruments, physical contracts and market access commitments. Financial instruments undertaken within our refining business by the operator, Phillips 66, are primarily for purchased product. For details of our financial instruments, including classification, assumptions made in the calculation of fair value and additional discussion on exposure of risks and the management of those risks, see Notes 3 and 32 to the Consolidated Financial Statements.
Impact of Financial Risk Management Activities
2015 | 2014 | |||||||||||||||||||||||||
($ millions) | Realized | Unrealized | Total | Realized | Unrealized | Total | ||||||||||||||||||||
Crude Oil |
|
(571 |
) |
123 | (448 | ) | (37 | ) | (536 | ) | (573 | ) | ||||||||||||||
Natural Gas |
(59 | ) | 55 | (4 | ) | (7 | ) | (55 | ) | (62 | ) | |||||||||||||||
Refining |
(36 | ) | 10 | (26 | ) | (26 | ) | (11 | ) | (37 | ) | |||||||||||||||
Power |
10 | 5 | 15 | 4 | 6 | 10 | ||||||||||||||||||||
Interest Rate |
- | 2 | 2 | - | - | - | ||||||||||||||||||||
(Gain) Loss on Risk Management |
(656 | ) | 195 | (461 | ) | (66 | ) | (596 | ) | (662 | ) | |||||||||||||||
Income Tax Expense (Recovery) |
175 | (54 | ) | 121 | 20 | 152 | 172 | |||||||||||||||||||
(Gain) Loss on Risk Management, After Tax |
(481 | ) | 141 | (340 | ) | (46 | ) | (444 | ) | (490 | ) |
In 2015, we recorded realized gains on crude oil and natural gas risk management activities, consistent with our contract prices exceeding the average benchmark price. We recorded unrealized losses on our crude oil and natural gas financial instruments primarily due to the realization of settled positions partially offset by changes in market prices.
Commodity Price Sensitivities Risk Management Positions
The following table summarizes the sensitivities of the fair value of our risk management positions to fluctuations in commodity prices with all other variables held constant. Management believes the price fluctuations identified in the table below are a reasonable measure of volatility. Fluctuations in commodity prices could have resulted in unrealized gains (losses) for the year on open risk management positions as at December 31, 2015 as follows:
Commodity | Sensitivity Range | Increase | Decrease | |||
| ||||||
Crude Oil Commodity Price |
± US$10 per bbl Applied to Brent and WTI Hedges | (243) | 245 | |||
Crude Oil Differential Price |
± US$5 per bbl Applied to Differential Hedges Tied to Production | 80 | (80) | |||
Condensate Commodity Price |
± US$10 per bbl Applied to Condensate Hedges | 23 | (23) | |||
Power Commodity Price |
± $25 per MWHr Applied to Power Hedge | 19 | (19) | |||
Interest Rate Swaps |
± 50 Basis Points | 38 | (46) | |||
|
Risks Associated with Derivative Financial Instruments
Financial instruments expose Cenovus to the risk that a counterparty will default on its contractual obligations. This risk is partially mitigated through credit exposure limits, frequent assessment of counterparty credit ratings and netting arrangements, as outlined in our Credit Policy.
Financial instruments also expose Cenovus to the risk of a loss from adverse changes in the market value of financial instruments or if were unable to fulfill our delivery obligations related to the underlying physical
Cenovus Energy Inc. | 34 | 2015 Managements Discussion and Analysis |
transaction. Financial instruments may limit the benefit to Cenovus if commodity price increases. These risks are minimized through hedging limits that are reviewed annually by the Board, as required by our Market Risk Mitigation Policy.
Liquidity
Liquidity risk is the risk we will not be able to meet all our financial obligations as they come due or be unable to liquidate assets in a timely manner at a reasonable price. In declining economic times, such as the low commodity price environment in which we are currently operating, or due to unforeseen events, our liquidity risk could become heightened.
Liquidity risk is further impacted by the amount and timing of financial and operating commitments, future capital expenditures, debt repayments as well as available sources of liquidity, which may be impacted by our credit ratings. If we were unable to meet our financial obligations as they became due or be unable to liquidate assets in a timely manner at a reasonable price, this could have a material adverse effect on our financial condition, results of operations, cash flows, access to capital, ability to comply with various financial and operating covenants, credit ratings and reputation.
We manage our liquidity risk through the active management of cash and debt by ensuring that we have access to multiple sources of capital including, but not limited to, cash and cash equivalents, cash from operating activities, undrawn credit facilities and availability under our shelf prospectuses. At December 31, 2015, we had cash and cash equivalents of $4.1 billion. No amounts were drawn on our $4.0 billion committed credit facility. In addition, we had $1.5 billion in unused capacity under our Canadian base shelf prospectus and US$2.0 billion in unused capacity under our U.S. base shelf prospectus, the availability of which is dependent on market conditions and our credit ratings. We intend to file a new prospectus prior to the maturity of the existing prospectuses.
Foreign Exchange Rates
Our revenues are subject to foreign exchange exposure as the sales prices of our crude oil, natural gas and refined products are determined by reference to U.S. benchmark prices. A decrease in the value of the Canadian dollar compared with the U.S. dollar has a positive impact on our reported results. Likewise, as the Canadian dollar strengthens, our reported results are lower. In addition to our revenues being denominated in U.S. dollars, we have chosen to borrow U.S. dollar long-term debt. In periods of a weakening Canadian dollar, our U.S. dollar debt gives rise to unrealized foreign exchange losses when translated to Canadian dollars. Exchange rate fluctuations could have a material adverse effect on our financial condition, results of operations and cash flows.
Operational Risk
Operational risks are those risks that affect our ability to continue operations in the ordinary course of business. Our operations are subject to risks generally affecting the oil and gas and refining industries. To partially mitigate our risk, we have a system of standards, practices and procedures called the Cenovus Operations Management System (COMS) to identify, assess and mitigate safety, operational and environmental risk across our operations. In addition to leveraging COMS, we attempt to partially mitigate operational risks by maintaining a comprehensive insurance program in respect of our assets and operations.
Market Access and Transportation Restrictions
Cenovuss production is transported through pipelines and by rail and its refineries are reliant on pipelines to receive feedstock. Disruptions in, or restricted availability of pipeline service or rail shipments, could adversely affect our crude oil and natural gas sales, projected production growth, refining operations and cash flows. Insufficient transportation capacity for our production will impact our ability to efficiently access end markets. This may negatively impact our financial performance by way of higher transportation costs, wider price differentials, lower sales prices at specific locations or for specific grades of crude oil, and in extreme situations, production curtailment.
Operational Outages and Major Environmental or Safety Incidents
Our crude oil and natural gas production activities are subject to inherent operational risks such as encountering unexpected formations or pressures, blowouts, equipment failures and other accidents, interdependence of component systems, sour gas releases, uncontrollable flows of crude oil, natural gas or well fluids, adverse weather conditions, pollution and other environmental risks. Our refining and marketing activities are subject to risks including slowdowns due to equipment failure or transportation disruptions, weather, fires, explosions, railcar incidents or derailments, unavailability of feedstock, and poor price and quality of feedstock. Cenovuss operations could also be interrupted by natural disasters or other events beyond our control.
Failure to manage these risks effectively could result in potential fatalities, serious injury, asset damage or environmental impacts, any of which could have a material adverse effect on our reputation, financial condition, results of operations and cash flows. Cenovus does not insure against all potential occurrences and disruptions and our insurance may be insufficient to cover any such occurrences or disruptions.
Project Execution
There are risks associated with the execution and operations of our upstream and refining growth and development projects. Successful project execution will be highly dependent upon the availability and cost of materials,
Cenovus Energy Inc. | 35 | 2015 Managements Discussion and Analysis |
equipment and skilled labour, our ability to finance growth and general economic conditions. Project execution will also be impacted by our ability to obtain the necessary environmental and regulatory approvals, and the effect of changing government regulations and public expectations in relation to the impact of oil sands development on the environment. The commissioning and integration of new facilities within our existing asset base could also cause delays in achieving targets and objectives. Failure to manage these risks could have a material adverse effect on our financial condition, results of operations and cash flows.
Cost Management
Our operating costs could escalate and become uncompetitive due to labour costs, equipment limitations, commodity prices, higher steam-to-oil ratios in our oil sands operations, additional government or environmental regulations and general inflationary pressures. Operating costs associated with our crude oil production are largely fixed in the short-term and, as a result, are largely dependent on levels of production. Our inability to manage costs may impact project returns and future development decisions, which could have a material adverse effect on our financial condition, results of operations and cash flows.
Reserves Replacement
If we fail to acquire, develop or find additional crude oil and natural gas reserves, our reserves and production will decline materially from their current levels. Our financial condition, results of operations and cash flows are highly dependent upon successfully producing from current reserves and acquiring, discovering or developing additional reserves.
Leadership and Talent
Our success in executing our business strategy is dependent upon Management and their leadership capabilities, as well as, the quality and competency of our employees. If we fail to retain critical talent or are unsuccessful in attracting and retaining new talent, with the necessary leadership traits, skills and technical competencies, it could have a materially adverse effect on Cenovuss results of operations, pace of growth and financial condition.
Regulatory Risk
Regulatory risk is the risk of loss or lost opportunity resulting from the introduction of, or changes in, regulatory requirements or the failure to secure regulatory approval for a crude oil or natural gas development project. The implementation of new regulations or the modification of existing regulations could impact our existing and planned projects as well as result in compliance costs, adversely impacting our financial condition, results of operations and cash flows.
Regulatory Approvals
Our operations are subject to regulation and intervention by governments in areas such as energy policies, environmental and safety policies, land tenure, taxes, royalties, government fees, the export of crude oil, natural gas and other products, production rates, expropriation or cancellation of contract rights, acquisition of exploration and production rights, and control over the development and abandonment of fields. Changes to government regulation could impact Cenovuss existing and planned projects or increase capital investment or operating expenses, adversely impacting our financial condition, results of operations and cash flows.
Royalty Regimes
The governments of Alberta and Saskatchewan receive royalties on the production of crude oil and natural gas from lands where they own the mineral rights. The Government of Alberta released its royalty review report on January 29, 2015. The report recommends no changes to existing oil sands royalty rates but recommended further government-industry consultation on administrative aspects of the oil sands royalty regime. The royalty review report recommended a modernization of Albertas conventional oil and gas royalty regime but did not provide details. The changes proposed to conventional oil and gas royalties will require further consultation between industry and government to fully understand their impacts. These changes to the Alberta provincial royalty structure could have a significant impact on Cenovuss financial condition, results of operations and cash flows. An increase in the royalty rates applicable in one or both provinces could make, in the respective province, future capital expenditures or existing operations uneconomic.
Environmental Regulations
Environmental regulations impose, among other things, restrictions, liabilities and obligations in connection with the generation, handling, use, storage, transportation, treatment and disposal of hazardous substances and waste and in connection with spills, releases and emissions of various substances in the environment. They also impose restrictions, liabilities and obligations in connection with the management of fresh or potable water sources that are being used, or whose use is contemplated, in connection with oil and gas operations. The complexities of changes in environmental regulations make it difficult to predict the potential future impact to Cenovus.
Compliance with environmental regulations can require significant expenditures, including clean-up costs and damages arising from contaminated properties. We anticipate that future capital expenditures and operating expenses could continue to increase as a result of the implementation of new environmental regulations.
Cenovus Energy Inc. | 36 | 2015 Managements Discussion and Analysis |
Failure to comply with environmental regulations may result in the imposition of fines, penalties and environmental protection orders. The costs of complying with environmental regulations in the future may have a material adverse effect on our financial condition, results of operations and cash flows. Non-compliance with environmental regulations could have an adverse impact on Cenovuss reputation. There is also a risk that Cenovus could face litigation initiated by third parties relating to climate change or other environmental regulations.
Species at Risk Act
The Canadian federal legislation, Species at Risk Act, and provincial counterparts regarding threatened or endangered species may influence development in areas identified as critical habitat for species of concern (e.g. woodland caribou). In Alberta, the Alberta Caribou Action and Range Planning Project has been established to develop range plans and action plans with a view to achieving the maintenance and recovery of Albertas 15 caribou populations. The federal and/or provincial implementation of measures to protect species at risk such as woodland caribou and their critical habitat in areas of Cenovuss current or future operations may limit our pace and amount of development and, in some cases, may result in an inability to operate in affected areas.
Climate Change
Various federal, provincial and state governments have announced intentions to regulate greenhouse gas (GHG) emissions and other air pollutants. In November, 2015, the Government of Alberta announced its climate leadership plan (the CLP) highlighting four key strategies that the government will implement to address climate change: (1) the complete phase-out of coal-fired sources of electricity by 2030; (2) an Alberta economy-wide price on GHG emissions of $30/tonne; (3) capping oil sands emissions to a province-wide total of 100 megatonnes per year, with certain exceptions for cogeneration power sources and new upgrading capacity; and (4) reducing methane emissions from oil and gas activities by 45 percent by 2025.
We are also subject to the Specified Gas Emitters Regulation (the SGER), which imposes GHG emissions intensity limits and reduction requirements for owners of facilities that emit 100,000 tonnes per year or more of GHG. Recent amendments to the SGER have increased the maximum emission intensity reduction requirement for facility owners from 12 percent to 15 percent in 2016 and 20 percent starting in 2017. One of the options for complying with the SGER is for facility owners to purchase technology fund credits. The SGER amendments have increased the price for such credits from $15/tonne to $20/tonne for 2016 and $30/tonne beginning in 2017.
If comprehensive GHG regulation is enacted in Alberta or any jurisdiction in which we operate, including legislation to implement the CLP, and as a result of the amendments to the SGER, we may incur increased compliance costs, loss of markets, permitting delays, substantial costs to generate or purchase emission credits or allowances, all of which may increase operating expenses and reduce demand for crude oil, natural gas and certain refined products.
Beyond existing legal requirements, the extent and magnitude of any adverse impacts of these additional programs cannot be reliably or accurately estimated at this time because specific legislative and regulatory requirements have not been finalized and uncertainty exists with respect to the additional measures being considered and the time frames for compliance.
Water Licenses
To operate our SAGD facilities we rely on water, which is obtained under licenses issued through the Alberta Water Act. Currently, we are not required to pay for the water we use under these licenses. If a change under these licenses reduces the amount of water available for our use, our production could decline or operating expenses could increase, both of which may have a material adverse effect on our business and financial performance. There can be no assurance that the licenses to withdraw water will not be rescinded or that additional conditions will not be added to these licenses. There can be no assurance that we will not have to pay a fee for the use of water in the future or that any such fees will be reasonable. In addition, the expansion of our projects rely on securing licenses for additional water withdrawal, and there can be no assurance that these licenses will be granted on terms favourable to us or at all, or that such additional water will in fact be available to divert under such licenses.
Albertas Land-Use Framework
The Government of Alberta approved the Lower Athabasca Regional Plan (LARP), which identifies legally binding management frameworks for air, land and water that will incorporate cumulative limits and triggers as well as identifying areas related to conservation, tourism and recreation. Uncertainty exists with respect to future development applications in the areas covered by the LARP, including the potential for development restrictions and mineral rights cancellation. This may have a material adverse effect on our financial condition, results of operations and cash flows. Additional regional plans are in the process of being developed by the Government of Alberta and no assurances can be given that such plans, if approved and implemented, will not materially impact our operations or future operations.
Cenovus Energy Inc. | 37 | 2015 Managements Discussion and Analysis |
CRITICAL ACCOUNTING JUDGMENTS, ESTIMATES AND ACCOUNTING POLICIES
Management is required to make estimates and assumptions, and use judgment in the application of accounting policies that could have a significant impact on our financial results. Actual results may differ from estimates and those differences may be material. The estimates and assumptions used are subject to updates based on experience and the application of new information. Our critical accounting policies and estimates are reviewed annually by the Audit Committee of the Board. Further details on the basis of preparation and our significant accounting policies can be found in the notes to the Consolidated Financial Statements.
Critical Judgments in Applying Accounting Policies
Critical judgments are those judgments made by Management in the process of applying accounting policies that have the most significant effect on the amounts recorded in our Consolidated Financial Statements.
Joint Arrangements
Cenovus holds a 50 percent ownership interest in two jointly controlled entities, FCCL and WRB. The classification of these joint arrangements as either a joint operation or a joint venture requires judgment. It was determined that Cenovus has the rights to the assets and obligations for the liabilities of FCCL and WRB. As a result, these joint arrangements are classified as joint operations and our share of the assets, liabilities, revenues and expenses are recorded in the Consolidated Financial Statements.
In determining the classification of its joint arrangements under IFRS 11, Joint Arrangements, we considered the following:
| The intention of the transaction creating FCCL and WRB was to form an integrated North American heavy oil business. The integrated business was structured, initially on a tax neutral basis, through two partnerships due to the assets residing in different tax jurisdictions. Partnerships are flow-through entities which have a limited life. |
| The partnership agreements require the partners (Cenovus and ConocoPhillips or Phillips 66 or respective subsidiaries) to make contributions if funds are insufficient to meet the obligations or liabilities of the partnership. The past and future development of FCCL and WRB is dependent on funding from the partners by way of partnership notes payable and loans. The partnerships do not have any third-party borrowings. |
| FCCL operates like most typical western Canadian working interest relationships where the operating partner takes product on behalf of the participants. WRB has a very similar structure modified only to account for the operating environment of the refining business. |
| Cenovus and Phillips 66, as operators, either directly or through wholly-owned subsidiaries, provide marketing services, purchase necessary feedstock, and arrange for transportation and storage on the partners behalf as the agreements prohibit the partnerships from undertaking these roles themselves. In addition, the partnerships do not have employees and as such are not capable of performing these roles. |
| In each arrangement, output is taken by one of the partners, indicating that the partners have rights to the economic benefits of the assets and the obligation for funding the liabilities of the arrangements. |
Exploration and Evaluation Assets
The application of Cenovuss accounting policy for E&E expenditures requires judgment in determining whether it is likely that future economic benefit exists when activities have not reached a stage where technical feasibility and commercial viability can be reasonably determined. Factors such as drilling results, future capital programs, future operating expenses, as well as estimated reserves and resources are considered. In addition, Management uses judgment to determine when E&E assets are reclassified to PP&E. In making this determination, various factors are considered, including the existence of reserves, and whether the appropriate approvals have been received from regulatory bodies and Cenovuss internal approval process.
Identification of CGUs
CGUs are defined as the lowest level of integrated assets for which there are separately identifiable cash flows that are largely independent of cash flows from other assets or groups of assets. The classification of assets and allocation of corporate assets into CGUs requires significant judgment and interpretations. Factors considered in the classification include the integration between assets, shared infrastructures, the existence of common sales points, geography, geologic structure, and the manner in which Management monitors and makes decisions about its operations. The recoverability of Cenovuss upstream, refining, crude-by-rail and corporate assets are assessed at the CGU level. As such, the determination of a CGU could have a significant impact on impairment losses.
Key Sources of Estimation Uncertainty
Critical accounting estimates are those estimates that require Management to make particularly subjective or complex judgments about matters that are inherently uncertain. Estimates and underlying assumptions are reviewed on an ongoing basis and any revisions to accounting estimates are recorded in the period in which the estimates are revised. The following are the key assumptions about the future and other key sources of estimation
Cenovus Energy Inc. | 38 | 2015 Managements Discussion and Analysis |
at the end of the reporting period that changes to could result in a material adjustment to the carrying amount of assets and liabilities within the next financial year.
Crude Oil and Natural Gas Reserves
There are a number of inherent uncertainties associated with estimating crude oil and natural gas reserves. Reserves estimates are dependent upon variables including the recoverable quantities of hydrocarbons, the cost of the development of the required infrastructure to recover the hydrocarbons, production costs, estimated selling price of the hydrocarbons produced, royalty payments and taxes. Changes in these variables could significantly impact the reserves estimates which would affect the impairment test and DD&A expense of our crude oil and natural gas assets in the Oil Sands and Conventional segments. Cenovuss crude oil and natural gas reserves are evaluated annually and reported to Cenovus by IQREs. Refer to the Outlook section of this MD&A for more details on future commodity prices.
Impairment of Assets
Impairment calculations require the use of estimates and assumptions, which are subject to change as new information becomes available. For our upstream assets, these estimates include forward commodity prices, expected production volumes, quantity of reserves and resources, discount rates, future development and operating expenses, and income tax rates. Recoverable amounts for the our refining assets and crude-by-rail terminal use assumptions such as throughput, forward commodity prices, operating expenses, transportation capacity, supply and demand conditions, and income tax rates. Changes in assumptions used in determining the recoverable amount could affect the carrying value of the related assets.
Refer to the Outlook section of this MD&A for more details on future commodity prices and to the reportable segments section of this MD&A for more details on impairments.
As at December 31, 2015, the recoverable amounts of Cenovuss upstream CGUs were determined based on fair value less costs of disposal. Key assumptions in the determination of cash flows from reserves include crude oil and natural gas prices, and the discount rate. All reserves have been evaluated at December 31, 2015 by IQREs.
Crude Oil and Natural Gas Prices
The future prices used to determine cash flows from crude oil and natural gas reserves are:
2016 | 2017 | 2018 | 2019 | 2020 | Average Annual % Change to 2026 |
|||||||||||||||||||
|
||||||||||||||||||||||||
WTI (US$/barrel) |
45.00 | 53.60 | 62.40 | 69.00 | 73.10 | 3.8% | ||||||||||||||||||
WCS ($/barrel) |
46.40 | 54.40 | 59.70 | 66.30 | 68.20 | 3.9% | ||||||||||||||||||
AECO ($/Mcf)(1) |
2.70 | 3.20 | 3.55 | 3.85 | 3.95 | 4.0% | ||||||||||||||||||
|
(1) | Assumes gas heating value of one million British Thermal Units per thousand cubic feet. |
Discount and Inflation Rates
Evaluations of discounted future cash flows are initiated using the discount rate of 10 percent and inflation is estimated at two percent, which is common industry practice and used by Cenovuss IQREs in preparing their reserves reports. Based on the individual characteristics of the asset, other economic and operating factors are also considered, which may increase or decrease the implied discount rate.
Decommissioning Costs
Provisions are recorded for the future decommissioning and restoration of our upstream crude oil and natural gas assets, refining assets and crude-by-rail terminal at the end of their economic lives. Management uses judgement to assess the existence and to estimate the future liability. The actual cost of decommissioning and restoration is uncertain and cost estimates may change in response to numerous factors including changes in legal requirements, technological advances, inflation and the timing of expected decommissioning and restoration. In addition, Management determines the appropriate discount rate at the end of each reporting period. This discount rate, which is credit adjusted, is used to determine the present value of the estimated future cash outflows required to settle the obligation and may change in response to numerous market factors. Refer to Note 22 of the Consolidated Financial Statements for more details on changes to decommissioning costs.
Income Tax Provisions
Tax regulations and legislation and the interpretations thereof in the various jurisdictions in which Cenovus operates are subject to change. There are usually a number of tax matters under review; therefore, income taxes are subject to measurement uncertainty.
Deferred income tax assets are recorded to the extent that it is probable that the deductible temporary differences will be recoverable in future periods. The recoverability assessment involves a significant amount of estimation including an evaluation of when the temporary differences will reverse, an analysis of the amount of future taxable earnings, the availability of cash flow to offset the tax assets when the reversal occurs and the application of tax laws. There are some transactions for which the ultimate tax determination is uncertain. To the extent that assumptions used in the recoverability assessment change, there may be a significant impact on the Consolidated
Cenovus Energy Inc. | 39 | 2015 Managements Discussion and Analysis |
Financial Statements of future periods. Refer to the Corporate and Eliminations section of this MD&A for more details on changes to estimates related to income taxes.
Changes in Accounting Policies
There were no new or amended accounting standards or interpretations adopted during 2015.
Future Accounting Pronouncements
A number of new accounting standards, amendments to accounting standards and interpretations are effective for annual periods beginning on or after January 1, 2016 and have not been applied in preparing the Consolidated Financial Statements for the year ended December 31, 2015. The standards applicable to Cenovus are as follows and will be adopted on their respective effective dates:
Leases
On January 13, 2016, the IASB issued IFRS 16, Leases (IFRS 16), which requires entities to recognize lease assets and lease obligations on the balance sheet. For lessees, IFRS 16 removes the classification of leases as either operating leases or finance leases, effectively treating all leases as finance leases. Certain short-term leases (less than 12 months) and leases of low-value assets are exempt from the requirements, and may continue to be treated as operating leases.
Lessors will continue with a dual lease classification model. Classification will determine how and when a lessor will recognize lease revenue, and what assets would be recorded.
IFRS 16 is effective for years beginning on or after January 1, 2019, with early adoption permitted if IFRS 15 Revenue From Contracts With Customers has been adopted. The standard may be applied retrospectively or using a modified retrospective approach. The Company is currently evaluating the impact of adopting IFRS 16 on the Consolidated Financial Statements.
Revenue Recognition
On May 28, 2014, the IASB issued IFRS 15, Revenue From Contracts With Customers (IFRS 15) replacing International Accounting Standard 11, Construction Contracts, International Accounting Standard 18, Revenue and several revenue-related interpretations. IFRS 15 establishes a single revenue recognition framework that applies to contracts with customers. The standard requires an entity to recognize revenue to reflect the transfer of goods and services for the amount it expects to receive, when control is transferred to the purchaser. Disclosure requirements have also been expanded.
IFRS 15 is effective for annual periods beginning on or after January 1, 2018. Early adoption is permitted. The standard may be applied retrospectively or using a modified retrospective approach. We are currently evaluating the impact of adopting IFRS 15 on the Consolidated Financial Statements.
Financial Instruments
On July 24, 2014, the IASB issued the final version of IFRS 9, Financial Instruments (IFRS 9) to replace IAS 39, Financial Instruments: Recognition and Measurement (IAS 39).
IFRS 9 introduces a single approach to determine whether a financial asset is measured at amortized cost or fair value and replaces the multiple rules in IAS 39. The approach is based on how an entity manages its financial instruments in the context of its business model and the contractual cash flow characteristics of the financial assets. For financial liabilities, IFRS 9 retains most of the IAS 39 requirements; however, where the fair value option is applied to financial liabilities, the change in fair value resulting from an entitys own credit risk is recorded in other comprehensive income rather than net earnings, unless this creates an accounting mismatch. In addition, a new expected credit loss model for calculating impairment on financial assets replaces the incurred loss impairment model used in IAS 39. The new model will result in more timely recognition of expected credit losses. IFRS 9 also includes a simplified hedge accounting model, aligning hedge accounting more closely with risk management. We do not currently apply hedge accounting.
IFRS 9 is effective for years beginning on or after January 1, 2018. Early adoption is permitted if IFRS 9 is adopted in its entirety at the beginning of a fiscal period. We are currently evaluating the impact of adopting IFRS 9 on the Consolidated Financial Statements.
Management, including our President & Chief Executive Officer and Executive Vice-President & Chief Financial Officer, has assessed the design and effectiveness of internal control over financial reporting (ICFR) and disclosure controls and procedures (DC&P) as at December 31, 2015. In making its assessment, Management used the Committee of Sponsoring Organizations of the Treadway Commission framework in Internal Control Integrated Framework (2013) to evaluate the design and effectiveness of internal control over financial reporting. Based on our evaluation, Management has concluded that both ICFR and DC&P were effective as at December 31, 2015.
Cenovus Energy Inc. | 40 | 2015 Managements Discussion and Analysis |
The effectiveness of our ICFR was audited by PricewaterhouseCoopers LLP, an independent firm of chartered professional accountants, as stated in their Report of Independent Registered Public Accounting Firm, which is included in our audited Consolidated Financial Statements for the year ended December 31, 2015. There have been no changes to ICFR during the year ended December 31, 2015 that have materially affected, or are reasonably likely to materially affect, ICFR.
Internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
We are committed to operating in a responsible manner and integrating our corporate responsibility principles in the way we conduct our business. Our Corporate Responsibility (CR) policy guides our activities in the areas of: Leadership; Corporate Governance and Business Practices; People; Environmental Performance; Stakeholder and Aboriginal Engagement; and Community Involvement and Investment.
We published our 2014 CR report in June 2015, detailing our efforts to accelerate our environmental performance, protect the health and safety of our staff, invest in and engage with the communities where we operate and maintain the highest standards of corporate governance. Our CR report also lists external recognition we received for our commitment to corporate responsibility and our efforts to balance economic, governance, social and environmental performance. Our CR policy and CR report are available on our website at cenovus.com.
We expect 2016 will be another challenging year for our industry. Maintaining our financial resilience remains a top priority. Our revised 2016 guidance reflects reduced capital spending plans, consistent with our expectation that commodity prices will continue to be low for a prolonged period of time.
The following outlook commentary is focused on the next 12 months.
Commodity Prices Underlying our Financial Results
Our crude oil pricing outlook is influenced by the following:
| We expect the general outlook for crude oil prices will be tied primarily to the supply response to the current price environment and the pace of growth of the global economy. Overall, we expect crude oil price volatility and a modest price improvement in 2016. Slower global supply growth, combined with annual increases in demand growth, should support prices in the second half of the year, constrained by the need to draw down surplus crude oil inventories and anticipated re-entry of Iranian crude oil into markets. We continue to anticipate slower supply growth from North American producers as a result of the significant reductions in capital spending. The low crude oil price environment also serves to help boost global economic momentum. |
|
We believe there is a risk that OPEC will attempt to gain market share by increasing rig counts or increasing OPEC production, which will depress crude oil prices, and that economic uncertainty in China may slow emerging market demand;
| We expect the Brent-WTI differential to remain narrow now that the U.S. has lifted restrictions on exporting crude oil to overseas markets. Overall, the differential will likely be set by transportation costs. The Brent-WTI differential is expected to remain volatile due to mismatches in demand, global imports and refinery turnarounds; and |
| We also expect that the WTI-WCS differential will remain wide due to additional Canadian supply growth and declining U.S. light tight oil supply. However, substantially wider differentials are unlikely due to excess rail capacity and further expansions on existing pipeline systems. |
Cenovus Energy Inc. | 41 | 2015 Managements Discussion and Analysis |
Refining crack spreads in 2016, as forecasted at January 29, 2016, are expected to strengthen late in the second quarter due to higher seasonal demand for refined products and then decline in the second half of the year.
Natural gas production is anticipated to increase marginally in 2016 due to low levels of drilling activity. However, warmer weather is expected to reduce residential and commercial demand, while coal-to-gas substitution in the power sector is expected to continue. As a result, natural gas prices are anticipated to remain weak through the first half of 2016.
The average foreign exchange forward price expected over the next 12 months is US$0.711/C$. We expect that the Canadian dollar, compared with the U.S. dollar, will remain relatively weak in the near term due to weak commodity prices and Canadian economic uncertainty. Overall, a weak Canadian dollar should have a positive impact on our revenues and Operating Cash Flow.
Our exposure to the light/heavy price differentials is composed of both a global light/heavy component as well as Canadian congestion. While we expect to see volatility in crude oil prices, we mitigate our exposure to light/heavy price differentials through the following:
● |
Integration having heavy oil refining capacity capable of processing Canadian heavy oil. From a value perspective, our refining business positions us to capture value from both the WTI-WCS differential for Canadian crude oil and the Brent-WTI differential from the sale of refined products; |
Protection Against Canadian Congestion
(1) Expected gross production capacity. (2) Excludes additional 18,000 bbls/d heavy oil capacity expected as a result of the Wood River debottlenecking project (expected in the second half of 2016). | ||
● |
Financial hedge transactions limiting the impact of fluctuations in upstream crude oil prices by entering into financial transactions that fix the WTI-WCS differential; |
|||
● |
Marketing arrangements limiting the impact of fluctuations in upstream crude oil prices by entering into physical supply transactions with fixed price components directly with refiners; and |
|||
● |
Transportation commitments and arrangements supporting transportation projects that move crude oil from our production areas to consuming markets and also to tidewater markets. |
|||
Key Priorities for 2016
Maintain Financial Resilience
Maintaining our financial resilience continues to be a top priority. At December 31, 2015, we had $4.1 billion of cash on hand and $4.0 billion of undrawn capacity under our committed credit facility. Our debt has a weighted average maturity of approximately 16 years, with no debt maturing until the fourth quarter of 2019. We also have Canadian and U.S. base shelf prospectuses, the availability of which is dependent on market conditions and our credit ratings. Although we have a strong balance sheet, we plan to undertake additional measures in 2016 to remain financially resilient, including reductions in capital, operating and general and administrative costs, as we anticipate commodity prices to remain low in the upcoming year.
Attack Cost Structures
We will continue to focus on reducing our cost structure. In 2015, we captured savings of approximately $540 million, relative to our budget, from capital, operating and general and administrative cost reductions. We believe approximately 60 percent of these cost savings are sustainable over the long term and were reflected in our original 2016 budget.
Cenovus Energy Inc. | 42 | 2015 Managements Discussion and Analysis |
We believe we are positioned to achieve additional sustainable cost reductions going forward. We anticipate capital investment in 2016 of $1.2 billion to $1.3 billion, a reduction of $200 million to $300 million from our original budget announced in December 2015. We are targeting $100 million to $200 million of further savings in operating, general and administrative and compensation costs. We must ensure that, over the long term, we maintain an efficient and sustainable cost structure, and maximize the strengths of our functional business model.
Disciplined and Value-added Growth
We are committed to exercising capital discipline. We will consider expanding existing projects and developing emerging opportunities only when we believe we will generate attractive potential returns for shareholders. Although we have some of the needed fiscal and regulatory clarity at the provincial level, additional certainty around federal fiscal and regulatory regimes, commodity prices and our ability to sustain cost reductions is required. We will only commit to project reactivation if it does not undermine the strength of our balance sheet.
Oil and Gas Information
The estimates of reserves and resources data and related information were prepared effective December 31, 2015 by independent qualified reserves evaluators, 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. January 1, 2016 price forecast. For additional information about our reserves, resources and other oil and gas information, see Reserves Data and Other Oil and Gas Information in our AIF for the year ended December 31, 2015 and our Resources Statement.
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 estimate of contingent resources has not been adjusted for risk based on the chance of development.
Economic contingent resources are those contingent resources that are currently economically recoverable based on specific forecasts of commodity prices and costs. In Cenovuss case, contingent resources were evaluated using the same commodity price assumptions that were used for the 2015 reserves evaluation, which comply with NI 51-101 requirements.
Prospective resources are those quantities of bitumen estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective resources have both an associated chance of discovery and a chance of development. Prospective resources are further subdivided in accordance with the level of certainty associated with recoverable estimates assuming their discovery and development and may be sub-classified based on project maturity. The estimate of prospective resources has not been adjusted for risk based on the chance of discovery or the chance of development.
Best estimate is considered to be the best estimate of the quantity of resources that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. Those resources that fall within the best estimate have a 50 percent probability that the actual quantities recovered will equal or exceed the estimate. The contingent resources were estimated for individual projects and then aggregated for disclosure purposes.
Barrels of Oil Equivalent Natural gas volumes have been converted to barrels of oil equivalent (BOE) on the basis of six Mcf to one barrel (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. Given that the value ratio based on the current price of crude oil compared with natural gas is significantly different from the energy equivalency conversion ratio of 6:1, utilizing a conversion on a 6:1 basis is not an accurate reflection of value.
Additional information with respect to the significant factors relevant to the resources estimates, the specific contingencies which prevent the classification of the contingent resources as reserves, pricing and additional
Cenovus Energy Inc. | 43 | 2015 Managements Discussion and Analysis |
reserves and other oil and gas information, including the material risks and uncertainties associated with reserves and resources estimates, is contained in our AIF and Form 40-F for the year ended December 31, 2015, and our Resources Statement, both available on SEDAR at sedar.com, EDGAR at sec.gov and on our website at cenovus.com.
Forward-looking Information
This document contains certain forward-looking statements and other information (collectively forward-looking information) about our current expectations, estimates and projections, made in light of our experience and perception of historical trends. Forward-looking information in this document is identified by words such as anticipate, believe, expect, estimate, plan, forecast or F, future, target, position, project, capacity, could, should, focus, goal, outlook, proposed, potential, may, schedule, on track, strategy, forward, opportunity or similar expressions and includes suggestions of future outcomes, including statements about: our strategy and related milestones and schedules; projected future value; projections for 2016 and future years; forecast operating and financial results; targets for our Debt to Capitalization and Debt to EBITDA ratios; planned capital expenditures, including the timing and financing thereof; expected future production, including the timing, stability or growth thereof; expected reserves and resources; broadening market access; expected capacities, including for projects, transportation and refining; improving cost structures, forecast cost savings and sustainability thereof; dividend plans and strategy anticipated timelines for future regulatory, partner or internal approvals; future impact of regulatory measures; forecast commodity prices and expected impact to Cenovus; future use and development of technology, including expected effects on our environmental impact; and projected shareholder return. Readers are cautioned not to place undue reliance on forward-looking information as our actual results may differ materially from those expressed or implied.
Developing forward-looking information involves reliance on a number of assumptions and consideration of certain risks and uncertainties, some of which are specific to Cenovus and others that apply to the industry generally. The factors or assumptions on which the forward-looking information is based include: assumptions inherent in our current guidance, available at cenovus.com; our projected capital investment levels, the flexibility of our capital spending plans and the associated source of funding; estimates of quantities of oil, bitumen, natural gas and liquids from properties and other sources not currently classified as proved; our ability to obtain necessary regulatory and partner approvals; the successful and timely implementation of capital projects or stages thereof; our ability to generate sufficient cash flow to meet our current and future obligations; and other risks and uncertainties described from time to time in the filings we make with securities regulatory authorities.
2016 guidance, as updated on February 11, 2016, assumes: Brent of US$52.75/bbl, WTI of US$49.00/bbl; WCS of US$34.50/bbl; NYMEX of US$2.50/MMBtu; AECO of $2.50/GJ; Chicago 3-2-1 crack spread of US$12.00/bbl; and an exchange rate of $0.75 US$/C$.
The risk factors and uncertainties that could cause our actual results to differ materially, include: volatility of and assumptions regarding oil and natural gas prices; the effectiveness of our risk management program, including the impact of derivative financial instruments, the success of our hedging strategies and the sufficiency of our liquidity position; the accuracy of cost estimates; commodity prices, currency and interest rates; product supply and demand; market competition, including from alternative energy sources; risks inherent in our 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 operation of our crude-by-rail terminal, including health, safety and environmental risks; maintaining desirable ratios of debt to adjusted EBITDA and net debt to adjusted EBITDA as well as debt to capitalization and net debt to capitalization; our ability to access various sources of debt and equity capital, generally, and on terms acceptable to us; our ability to finance growth and sustaining capital expenditures; changes in credit ratings applicable to us or any of our securities; changes to our dividend plans or strategy, including the dividend reinvestment plan; accuracy of our reserves, resources and future production estimates; our ability to replace and expand oil and gas reserves; our ability to maintain our relationships with our partners and to successfully manage and operate our integrated business; reliability of our 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 acceptance in the market; unexpected cost increases or technical difficulties in constructing or modifying manufacturing or refining facilities; unexpected difficulties in producing, transporting or refining of crude oil into petroleum and chemical products; risks associated with technology and its application to our business; the timing and the costs of well and pipeline construction; our ability to secure adequate product transportation, including sufficient pipeline, crude-by-rail, marine or other alternate transportation, including to address any gaps caused by constraints in the pipeline system; availability of, and our ability to attract and retain, critical talent; changes in the regulatory framework in any of the locations in which we operate, including changes to the regulatory approval process and land-use designations, royalty, tax, environmental, greenhouse gas, carbon and other laws or regulations, or changes to the interpretation of such laws and regulations, as adopted or proposed, the impact thereof and the costs associated with compliance; the expected impact and timing of various accounting pronouncements, rule changes and standards on our business, our financial results and our consolidated financial statements; changes in the general economic, market and business conditions; the political and economic conditions in the countries in which we operate; the occurrence of unexpected events such as war, terrorist threats and the instability resulting therefrom; and risks associated with existing and potential future lawsuits and regulatory actions against us.
Readers are cautioned that the foregoing lists are not exhaustive and are made as at the date hereof. For a full discussion of our material risk factors, see Risk Factors in our AIF or Form 40-F for the period ended December 31, 2015, available on SEDAR at sedar.com, EDGAR at sec.gov and on our website at cenovus.com.
Cenovus Energy Inc. | 44 | 2015 Managements Discussion and Analysis |
The following abbreviations have been used in this document:
Crude Oil | Natural Gas | |||||
bbl |
barrel |
Mcf |
thousand cubic feet | |||
bbls/d |
barrels per day |
MMcf |
million cubic feet | |||
Mbbls/d |
thousand barrels per day |
Bcf |
billion cubic feet | |||
MMbbls |
million barrels |
MMBtu |
million British thermal units | |||
BOE |
barrel of oil equivalent |
GJ |
gigajoule | |||
BOE/d |
barrel of oil equivalent per day |
AECO |
Alberta Energy Company | |||
MBOE |
thousand barrel of oil equivalent |
NYMEX |
New York Mercantile Exchange | |||
MMBOE |
million barrel of oil equivalent |
|||||
WTI |
West Texas Intermediate |
|||||
WCS |
Western Canadian Select |
|||||
CDB |
Christina Dilbit Blend |
TM |
trademark of Cenovus Energy Inc. |
Cenovus Energy Inc. | 45 | 2015 Managements Discussion and Analysis |
Cenovus Energy Inc.
Consolidated Financial Statements
For the Year Ended December 31, 2015
(Canadian Dollars)
CONSOLIDATED FINANCIAL STATEMENTS
For the year ended December 31, 2015
TABLE OF CONTENTS
3 | ||||
4 | ||||
5 | ||||
5 | ||||
6 | ||||
7 | ||||
8 | ||||
9 | ||||
9 | ||||
13 | ||||
13 | ||||
4. CRITICAL ACCOUNTING JUDGMENTS AND KEY SOURCES OF ESTIMATION UNCERTAINTY |
21 | |||
23 | ||||
23 | ||||
23 | ||||
24 | ||||
24 | ||||
26 | ||||
29 | ||||
29 | ||||
29 | ||||
30 | ||||
30 | ||||
31 | ||||
32 | ||||
32 | ||||
32 | ||||
32 | ||||
32 | ||||
34 | ||||
34 | ||||
35 | ||||
38 | ||||
39 | ||||
39 | ||||
43 | ||||
43 | ||||
44 | ||||
45 | ||||
47 | ||||
50 | ||||
50 |
Cenovus Energy Inc. | 2 | Consolidated Financial Statements |
Managements Responsibility for the Consolidated Financial Statements
The accompanying Consolidated Financial Statements of Cenovus Energy Inc. are the responsibility of Management. The Consolidated Financial Statements have been prepared by Management in Canadian dollars in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board and include certain estimates that reflect Managements best judgments.
The Board of Directors has approved the information contained in the Consolidated Financial Statements. The Board of Directors fulfills its responsibility regarding the financial statements mainly through its Audit Committee which is made up of four independent directors. The Audit Committee has a written mandate that complies with the current requirements of Canadian securities legislation and the United States Sarbanes Oxley Act of 2002 and voluntarily complies, in principle, with the Audit Committee guidelines of the New York Stock Exchange. The Audit Committee meets with Management and the independent auditors on at least a quarterly basis to review and approve interim Consolidated Financial Statements and Managements Discussion and Analysis prior to their public release as well as annually to review the annual Consolidated Financial Statements and Managements Discussion and Analysis and recommend their approval to the Board of Directors.
Managements Assessment of Internal Control over Financial Reporting
Management is also responsible for establishing and maintaining adequate internal control over financial reporting. The internal control system was designed to provide reasonable assurance to Management regarding the preparation and presentation of the Consolidated Financial Statements.
Internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management has assessed the design and effectiveness of internal control over financial reporting as at December 31, 2015. In making its assessment, Management has used the Committee of Sponsoring Organizations of the Treadway Commission (COSO) framework in Internal Control Integrated Framework (2013) to evaluate the design and effectiveness of internal control over financial reporting. Based on our evaluation, Management has concluded that internal control over financial reporting was effective as at December 31, 2015.
PricewaterhouseCoopers LLP, an independent firm of Chartered Professional Accountants, was appointed to audit and provide independent opinions on both the Consolidated Financial Statements and internal control over financial reporting as at December 31, 2015, as stated in their Report of Independent Registered Public Accounting Firm dated February 10, 2016. PricewaterhouseCoopers LLP has provided such opinions.
/s/ Brian C. Ferguson |
/s/ Ivor M. Ruste | |
Brian C. Ferguson |
Ivor M. Ruste | |
President & |
Executive Vice-President & | |
Chief Executive Officer |
Chief Financial Officer | |
Cenovus Energy Inc. |
Cenovus Energy Inc. | |
February 10, 2016 |
Cenovus Energy Inc. | 3 | Consolidated Financial Statements |
Report of Independent Registered Public Accounting Firm
To the Shareholders of Cenovus Energy Inc.
We have audited the accompanying Consolidated Balance Sheets of Cenovus Energy Inc. as of December 31, 2015 and December 31, 2014 and the Consolidated Statements of Earnings, Comprehensive Income, Shareholders Equity and Cash Flows for each of the years in the three-year period ended December 31, 2015. We also have audited Cenovus Energy Inc.s internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Management is responsible for these Consolidated Financial Statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Report of Management. Our responsibility is to express an opinion on these Consolidated Financial Statements and an opinion on Cenovus Energy Inc.s internal control over financial reporting based on our integrated audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the Consolidated Financial Statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the Consolidated Financial Statements included examining, on a test basis, evidence supporting the amounts and disclosures in the Consolidated Financial Statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall Consolidated Financial Statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A companys internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A companys internal control over financial reporting includes those policies and procedures that: (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the companys assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Consolidated Financial Statements referred to above present fairly, in all material respects, the financial position of Cenovus Energy Inc. as of December 31, 2015 and December 31, 2014 and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2015 in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board. Also, in our opinion, Cenovus Energy Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control Integrated Framework (2013) issued by COSO.
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
Chartered Professional Accountants
Calgary, Alberta, Canada
February 10, 2016
Cenovus Energy Inc. | 4 | Consolidated Financial Statements |
CONSOLIDATED STATEMENTS OF EARNINGS
For the years ended December 31,
($ millions, except per share amounts)
See accompanying Notes to Consolidated Financial Statements.
Cenovus Energy Inc. | 5 | Consolidated Financial Statements |
As at December 31,
($ millions)
Notes | 2015 | 2014 | ||||||||||||||
Assets |
||||||||||||||||
Current Assets |
||||||||||||||||
Cash and Cash Equivalents |
12 | 4,105 | 883 | |||||||||||||
Accounts Receivable and Accrued Revenues |
13 | 1,251 | 1,582 | |||||||||||||
Income Tax Receivable |
6 | 28 | ||||||||||||||
Inventories |
14 | 810 | 1,224 | |||||||||||||
Risk Management |
31,32 | 301 | 478 | |||||||||||||
Current Assets |
6,473 | 4,195 | ||||||||||||||
Exploration and Evaluation Assets |
1,15 | 1,575 | 1,625 | |||||||||||||
Property, Plant and Equipment, Net |
1,16 | 17,335 | 18,563 | |||||||||||||
Income Tax Receivable |
90 | - | ||||||||||||||
Other Assets |
18 | 76 | 70 | |||||||||||||
Goodwill |
1,19 | 242 | 242 | |||||||||||||
Total Assets |
25,791 | 24,695 | ||||||||||||||
Liabilities and Shareholders Equity |
||||||||||||||||
Current Liabilities |
||||||||||||||||
Accounts Payable and Accrued Liabilities |
20 | 1,702 | 2,588 | |||||||||||||
Income Tax Payable |
133 | 357 | ||||||||||||||
Risk Management |
31,32 | 23 | 12 | |||||||||||||
Current Liabilities |
1,858 | 2,957 | ||||||||||||||
Long-Term Debt |
21 | 6,525 | 5,458 | |||||||||||||
Risk Management |
31,32 | 7 | 4 | |||||||||||||
Decommissioning Liabilities |
22 | 2,052 | 2,616 | |||||||||||||
Other Liabilities |
23 | 142 | 172 | |||||||||||||
Deferred Income Taxes |
10 | 2,816 | 3,302 | |||||||||||||
Total Liabilities |
13,400 | 14,509 | ||||||||||||||
Shareholders Equity |
12,391 | 10,186 | ||||||||||||||
Total Liabilities and Shareholders Equity |
25,791 | 24,695 | ||||||||||||||
Commitments and Contingencies |
34 |
See accompanying Notes to Consolidated Financial Statements.
Approved by the Board of Directors
/s/ Michael A. Grandin | /s/ Colin Taylor | |
Michael A. Grandin |
Colin Taylor | |
Director | Director | |
Cenovus Energy Inc. | Cenovus Energy Inc. |
Cenovus Energy Inc. | 6 | Consolidated Financial Statements |
CONSOLIDATED STATEMENTS OF SHAREHOLDERS EQUITY
($ millions)
Share Capital |
Paid in Surplus |
Retained Earnings |
AOCI (1) | Total | ||||||||||||||||||||||||
(Note 25 | ) | (Note 25 | ) | (Note 26 | ) | |||||||||||||||||||||||
Balance as at December 31, 2012 |
3,829 | 4,154 | 1,730 | 69 | 9,782 | |||||||||||||||||||||||
Net Earnings |
- | - | 662 | - | 662 | |||||||||||||||||||||||
Other Comprehensive Income (Loss) |
- | - | - | 141 | 141 | |||||||||||||||||||||||
Total Comprehensive Income (Loss) |
- | - | 662 | 141 | 803 | |||||||||||||||||||||||
Common Shares Issued Under Stock Option Plans |
31 | - | - | - | 31 | |||||||||||||||||||||||
Common Shares Cancelled |
(3 | ) | 3 | - | - | - | ||||||||||||||||||||||
Stock-Based Compensation Expense |
- | 62 | - | - | 62 | |||||||||||||||||||||||
Dividends on Common Shares |
- | - | (732 | ) | - | (732 | ) | |||||||||||||||||||||
Balance as at December 31, 2013 |
3,857 | 4,219 | 1,660 | 210 | 9,946 | |||||||||||||||||||||||
Net Earnings |
- | - | 744 | - | 744 | |||||||||||||||||||||||
Other Comprehensive Income (Loss) |
- | - | - | 197 | 197 | |||||||||||||||||||||||
Total Comprehensive Income (Loss) |
- | - | 744 | 197 | 941 | |||||||||||||||||||||||
Common Shares Issued Under Stock Option Plans |
32 | - | - | - | 32 | |||||||||||||||||||||||
Stock-Based Compensation Expense |
- | 72 | - | - | 72 | |||||||||||||||||||||||
Dividends on Common Shares |
- | - | (805 | ) | - | (805 | ) | |||||||||||||||||||||
Balance as at December 31, 2014 |
3,889 | 4,291 | 1,599 | 407 | 10,186 | |||||||||||||||||||||||
Net Earnings |
- | - | 618 | - | 618 | |||||||||||||||||||||||
Other Comprehensive Income (Loss) |
- | - | - | 613 | 613 | |||||||||||||||||||||||
Total Comprehensive Income (Loss) |
- | - | 618 | 613 | 1,231 | |||||||||||||||||||||||
Common Shares Issued for Cash |
1,463 | - | - | - | 1,463 | |||||||||||||||||||||||
Common Shares Issued Pursuant to Dividend Reinvestment Plan |
182 | - | - | - | 182 | |||||||||||||||||||||||
Common Shares Issued Under Stock Option Plans |
- | - | - | - | - | |||||||||||||||||||||||
Stock-Based Compensation Expense |
- | 39 | - | - | 39 | |||||||||||||||||||||||
Dividends on Common Shares |
- | - | (710 | ) | - | (710 | ) | |||||||||||||||||||||
Balance as at December 31, 2015 |
5,534 | 4,330 | 1,507 | 1,020 | 12,391 | |||||||||||||||||||||||
(1) | Accumulated Other Comprehensive Income (Loss). |
See accompanying Notes to Consolidated Financial Statements.
Cenovus Energy Inc. | 7 | Consolidated Financial Statements |
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the years ended December 31,
($ millions)
Notes | 2015 | 2014 | 2013 | |||||||||||||||||
Operating Activities |
||||||||||||||||||||
Net Earnings |
618 | 744 | 662 | |||||||||||||||||
Depreciation, Depletion and Amortization |
9,16 | 2,114 | 1,946 | 1,833 | ||||||||||||||||
Goodwill Impairment |
9 | - | 497 | - | ||||||||||||||||
Exploration Expense |
9,15 | 138 | 86 | 50 | ||||||||||||||||
Deferred Income Taxes |
10 | (655 | ) | 359 | 244 | |||||||||||||||
Unrealized (Gain) Loss on Risk Management |
31 | 195 | (596 | ) | 415 | |||||||||||||||
Unrealized Foreign Exchange (Gain) Loss |
7 | 1,097 | 411 | 40 | ||||||||||||||||
(Gain) Loss on Divestiture of Assets |
8 | (2,392 | ) | (156 | ) | 1 | ||||||||||||||
Current Tax on Divestiture of Assets |
8 | 391 | - | - | ||||||||||||||||
Unwinding of Discount on Decommissioning Liabilities |
5,22 | 126 | 120 | 97 | ||||||||||||||||
Other |
59 | 68 | 267 | |||||||||||||||||
Net Change in Other Assets and Liabilities |
(107 | ) | (135 | ) | (120 | ) | ||||||||||||||
Net Change in Non-Cash Working Capital |
(110 | ) | 182 | 50 | ||||||||||||||||
Cash From Operating Activities |
1,474 | 3,526 | 3,539 | |||||||||||||||||
Investing Activities |
||||||||||||||||||||
Capital Expenditures Exploration and Evaluation Assets |
15 | (138 | ) | (279 | ) | (331 | ) | |||||||||||||
Capital Expenditures Property, Plant and Equipment |
16 | (1,576 | ) | (2,779 | ) | (2,938 | ) | |||||||||||||
Acquisition |
17 | (84 | ) | - | - | |||||||||||||||
Proceeds From Divestiture of Assets |
8 | 3,344 | 276 | 258 | ||||||||||||||||
Current Tax on Divestiture of Assets |
8 | (391 | ) | - | - | |||||||||||||||
Net Change in Investments and Other |
3 | (1,583 | ) | 1,486 | ||||||||||||||||
Net Change in Non-Cash Working Capital |
(270 | ) | 15 | 6 | ||||||||||||||||
Cash From (Used in) Investing Activities |
888 | (4,350 | ) | (1,519 | ) | |||||||||||||||
Net Cash Provided (Used) Before Financing Activities |
2,362 | (824 | ) | 2,020 | ||||||||||||||||
Financing Activities |
||||||||||||||||||||
Net Issuance (Repayment) of Short-Term Borrowings |
(25 | ) | (18 | ) | (8 | ) | ||||||||||||||
Issuance of U.S. Unsecured Notes |
21 | - | - | 814 | ||||||||||||||||
Repayment of U.S. Unsecured Notes |
21 | - | - | (825 | ) | |||||||||||||||
Common Shares Issued, Net of Issuance Costs |
25 | 1,449 | - | - | ||||||||||||||||
Common Shares Issued Under Stock Option Plans |
- | 28 | 28 | |||||||||||||||||
Dividends Paid on Common Shares |
11 | (528 | ) | (805 | ) | (732 | ) | |||||||||||||
Other |
(2 | ) | (2 | ) | (3 | ) | ||||||||||||||
Cash From (Used in) Financing Activities |
894 | (797 | ) | (726 | ) | |||||||||||||||
Foreign Exchange Gain (Loss) on Cash and Cash Equivalents Held in Foreign Currency |
(34 | ) | 52 | (2 | ) | |||||||||||||||
Increase (Decrease) in Cash and Cash Equivalents |
3,222 | (1,569 | ) | 1,292 | ||||||||||||||||
Cash and Cash Equivalents, Beginning of Year |
883 | 2,452 | 1,160 | |||||||||||||||||
Cash and Cash Equivalents, End of Year |
4,105 | 883 | 2,452 | |||||||||||||||||
Supplementary Cash Flow Information |
33 | |||||||||||||||||||
See accompanying Notes to Consolidated Financial Statements.
Cenovus Energy Inc. | 8 | Consolidated Financial Statements |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2015
1. DESCRIPTION OF BUSINESS AND SEGMENTED DISCLOSURES
Cenovus Energy Inc. and its subsidiaries, (together Cenovus or the Company) are in the business of developing, producing and marketing crude oil, natural gas liquids (NGLs) and natural gas in Canada with marketing activities and refining operations in the United States (U.S.).
Cenovus is incorporated under the Canada Business Corporations Act and its shares are listed on the Toronto (TSX) and New York (NYSE) stock exchanges. The executive and registered office is located at 2600, 500 Centre Street S.E., Calgary, Alberta, Canada, T2G 1A6. Information on the Companys basis of preparation for these Consolidated Financial Statements is found in Note 2.
Management has determined the operating segments based on information regularly reviewed for the purposes of decision making, allocating resources and assessing operational performance by Cenovuss chief operating decision makers. The Company evaluates the financial performance of its operating segments primarily based on operating cash flow. The Companys reportable segments are:
| Oil Sands, which includes the development and production of bitumen and natural gas in northeast Alberta. Cenovuss bitumen assets include Foster Creek, Christina Lake and Narrows Lake as well as projects in the early stages of development, such as Grand Rapids and Telephone Lake. Certain of the Companys operated oil sands properties, notably Foster Creek, Christina Lake and Narrows Lake, are jointly owned with ConocoPhillips, an unrelated U.S. public company. |
| Conventional, which includes the development and production of conventional crude oil, NGLs and natural gas in Alberta and Saskatchewan, including the heavy oil assets at Pelican Lake, the carbon dioxide enhanced oil recovery project at Weyburn and emerging tight oil opportunities. |
| Refining and Marketing, which is responsible for transporting, selling and refining crude oil into petroleum and chemical products. Cenovus jointly owns two refineries in the U.S. with the operator Phillips 66, an unrelated U.S. public company. In addition, Cenovus owns and operates a crude-by-rail terminal in Alberta. This segment coordinates Cenovuss marketing and transportation initiatives to optimize product mix, delivery points, transportation commitments and customer diversification. The marketing of crude oil and natural gas sourced from Canada, including physical product sales that settle in the U.S., is considered to be undertaken by a Canadian business. U.S. sourced crude oil and natural gas purchases and sales are attributed to the U.S. |
| Corporate and Eliminations, which primarily includes unrealized gains and losses recorded on derivative financial instruments, gains and losses on divestiture of assets, as well as other Cenovus-wide costs for general and administrative, financing activities and research costs. As financial instruments are settled, the realized gains and losses are recorded in the operating segment to which the derivative instrument relates. Eliminations relate to sales and operating revenues, and purchased product between segments, recorded at transfer prices based on current market prices, and to unrealized intersegment profits in inventory. The Corporate and Eliminations segment is attributed to Canada, with the exception of unrealized risk management gains and losses, which have been attributed to the country in which the transacting entity resides. |
The following tabular financial information presents the segmented information first by segment, then by product and geographic location.
Cenovus Energy Inc. | 9 | Consolidated Financial Statements |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2015
A) Results of Operations Segment and Operational Information
Oil Sands | Conventional | Refining and Marketing | ||||||||||||||||||||||||||||||||||||||||||||||||||
For the years ended December 31, | 2015 | 2014 | 2013 | 2015 | 2014 | 2013 | 2015 | 2014 | 2013 | |||||||||||||||||||||||||||||||||||||||||||
Revenues |
||||||||||||||||||||||||||||||||||||||||||||||||||||
Gross Sales |
3,030 | 5,036 | 3,912 | 1,709 | 3,225 | 2,980 | 8,805 | 12,658 | 12,706 | |||||||||||||||||||||||||||||||||||||||||||
Less: Royalties |
29 | 236 | 132 | 114 | 229 | 204 | - | - | - | |||||||||||||||||||||||||||||||||||||||||||
3,001 | 4,800 | 3,780 | 1,595 | 2,996 | 2,776 | 8,805 | 12,658 | 12,706 | ||||||||||||||||||||||||||||||||||||||||||||
Expenses |
||||||||||||||||||||||||||||||||||||||||||||||||||||
Purchased Product |
- | - | - | - | - | - | 7,709 | 11,767 | 11,004 | |||||||||||||||||||||||||||||||||||||||||||
Transportation and Blending |
1,815 | 2,131 | 1,749 | 230 | 346 | 325 | - | - | - | |||||||||||||||||||||||||||||||||||||||||||
Operating |
531 | 639 | 548 | 561 | 709 | 701 | 754 | 703 | 538 | |||||||||||||||||||||||||||||||||||||||||||
Production and Mineral Taxes |
- | - | - | 18 | 46 | 35 | - | - | - | |||||||||||||||||||||||||||||||||||||||||||
(Gain) Loss on Risk Management |
(404 | ) | (38 | ) | (37 | ) | (209 | ) | (1 | ) | (104 | ) | (43 | ) | (27 | ) | 19 | |||||||||||||||||||||||||||||||||||
Operating Cash Flow |
1,059 | 2,068 | 1,520 | 995 | 1,896 | 1,819 | 385 | 215 | 1,145 | |||||||||||||||||||||||||||||||||||||||||||
Depreciation, Depletion and Amortization |
697 | 625 | 446 | 1,148 | 1,082 | 1,170 | 191 | 156 | 138 | |||||||||||||||||||||||||||||||||||||||||||
Goodwill Impairment |
- | - | - | - | 497 | - | - | - | - | |||||||||||||||||||||||||||||||||||||||||||
Exploration Expense |
67 | 4 | - | 71 | 82 | 114 | - | - | - | |||||||||||||||||||||||||||||||||||||||||||
Segment Income (Loss) |
295 | 1,439 | 1,074 | (224 | ) | 235 | 535 | 194 | 59 | 1,007 | ||||||||||||||||||||||||||||||||||||||||||
Corporate and Eliminations | Consolidated | |||||||||||||||||||||||||||||||||||||||||||||||||||
For the years ended December 31, | 2015 | 2014 | 2013 | 2015 | 2014 | 2013 | ||||||||||||||||||||||||||||||||||||||||||||||
Revenues |
||||||||||||||||||||||||||||||||||||||||||||||||||||
Gross Sales |
(337 | ) | (812 | ) | (605 | ) | 13,207 | 20,107 | 18,993 | |||||||||||||||||||||||||||||||||||||||||||
Less: Royalties |
- | - | - | 143 | 465 | 336 | ||||||||||||||||||||||||||||||||||||||||||||||
(337 | ) | (812 | ) | (605 | ) | 13,064 | 19,642 | 18,657 | ||||||||||||||||||||||||||||||||||||||||||||
Expenses |
||||||||||||||||||||||||||||||||||||||||||||||||||||
Purchased Product |
(335 | ) | (812 | ) | (605 | ) | 7,374 | 10,955 | 10,399 | |||||||||||||||||||||||||||||||||||||||||||
Transportation and Blending |
(2 | ) | - | - | 2,043 | 2,477 | 2,074 | |||||||||||||||||||||||||||||||||||||||||||||
Operating |
(7 | ) | (6 | ) | (5 | ) | 1,839 | 2,045 | 1,782 | |||||||||||||||||||||||||||||||||||||||||||
Production and Mineral Taxes |
- | - | - | 18 | 46 | 35 | ||||||||||||||||||||||||||||||||||||||||||||||
(Gain) Loss on Risk Management |
195 | (596 | ) | 415 | (461 | ) | (662 | ) | 293 | |||||||||||||||||||||||||||||||||||||||||||
Depreciation, Depletion and Amortization |
78 | 83 | 79 | 2,114 | 1,946 | 1,833 | ||||||||||||||||||||||||||||||||||||||||||||||
Goodwill Impairment |
- | - | - | - | 497 | - | ||||||||||||||||||||||||||||||||||||||||||||||
Exploration Expense |
- | - | - | 138 | 86 | 114 | ||||||||||||||||||||||||||||||||||||||||||||||
Segment Income (Loss) |
(266 | ) | 519 | (489 | ) | (1 | ) | 2,252 | 2,127 | |||||||||||||||||||||||||||||||||||||||||||
General and Administrative |
335 | 379 | 365 | 335 | 379 | 365 | ||||||||||||||||||||||||||||||||||||||||||||||
Finance Costs |
482 | 445 | 529 | 482 | 445 | 529 | ||||||||||||||||||||||||||||||||||||||||||||||
Interest Income |
(28 | ) | (33 | ) | (96 | ) | (28 | ) | (33 | ) | (96 | ) | ||||||||||||||||||||||||||||||||||||||||
Foreign Exchange (Gain) Loss, Net |
1,036 | 411 | 208 | 1,036 | 411 | 208 | ||||||||||||||||||||||||||||||||||||||||||||||
Research Costs |
27 | 15 | 24 | 27 | 15 | 24 | ||||||||||||||||||||||||||||||||||||||||||||||
(Gain) Loss on Divestiture of Assets |
(2,392 | ) | (156 | ) | 1 | (2,392 | ) | (156 | ) | 1 | ||||||||||||||||||||||||||||||||||||||||||
Other (Income) Loss, Net |
2 | (4 | ) | 2 | 2 | (4 | ) | 2 | ||||||||||||||||||||||||||||||||||||||||||||
(538 | ) | 1,057 | 1,033 | (538 | ) | 1,057 | 1,033 | |||||||||||||||||||||||||||||||||||||||||||||
Earnings Before Income Tax |
537 | 1,195 | 1,094 | |||||||||||||||||||||||||||||||||||||||||||||||||
Income Tax Expense (Recovery) |
(81 | ) | 451 | 432 | ||||||||||||||||||||||||||||||||||||||||||||||||
Net Earnings |
618 | 744 | 662 |
Cenovus Energy Inc. | 10 | Consolidated Financial Statements |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2015
B) Financial Results by Upstream Product
Crude Oil (1) | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Oil Sands | Conventional | Total | ||||||||||||||||||||||||||||||||||||||||||||||||||
For the years ended December 31, | 2015 | 2014 | 2013 | 2015 | 2014 | 2013 | 2015 | 2014 | 2013 | |||||||||||||||||||||||||||||||||||||||||||
Revenues |
||||||||||||||||||||||||||||||||||||||||||||||||||||
Gross Sales |
3,000 | 4,963 | 3,850 | 1,239 | 2,456 | 2,373 | 4,239 | 7,419 | 6,223 | |||||||||||||||||||||||||||||||||||||||||||
Less: Royalties |
29 | 233 | 131 | 103 | 217 | 196 | 132 | 450 | 327 | |||||||||||||||||||||||||||||||||||||||||||
2,971 | 4,730 | 3,719 | 1,136 | 2,239 | 2,177 | 4,107 | 6,969 | 5,896 | ||||||||||||||||||||||||||||||||||||||||||||
Expenses |
||||||||||||||||||||||||||||||||||||||||||||||||||||
Transportation and Blending |
1,814 | 2,130 | 1,748 | 213 | 326 | 305 | 2,027 | 2,456 | 2,053 | |||||||||||||||||||||||||||||||||||||||||||
Operating |
511 | 615 | 527 | 381 | 505 | 489 | 892 | 1,120 | 1,016 | |||||||||||||||||||||||||||||||||||||||||||
Production and Mineral Taxes |
- | - | - | 16 | 37 | 32 | 16 | 37 | 32 | |||||||||||||||||||||||||||||||||||||||||||
(Gain) Loss on Risk Management |
(400 | ) | (38 | ) | (33 | ) | (157 | ) | 4 | (43 | ) | (557 | ) | (34 | ) | (76 | ) | |||||||||||||||||||||||||||||||||||
Operating Cash Flow |
1,046 | 2,023 | 1,477 | 683 | 1,367 | 1,394 | 1,729 | 3,390 | 2,871 | |||||||||||||||||||||||||||||||||||||||||||
(1) Includes NGLs. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Natural Gas | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Oil Sands | Conventional | Total | ||||||||||||||||||||||||||||||||||||||||||||||||||
For the years ended December 31, | 2015 | 2014 | 2013 | 2015 | 2014 | 2013 | 2015 | 2014 | 2013 | |||||||||||||||||||||||||||||||||||||||||||
Revenues |
||||||||||||||||||||||||||||||||||||||||||||||||||||
Gross Sales |
22 | 67 | 38 | 450 | 744 | 594 | 472 | 811 | 632 | |||||||||||||||||||||||||||||||||||||||||||
Less: Royalties |
- | 3 | 1 | 11 | 12 | 8 | 11 | 15 | 9 | |||||||||||||||||||||||||||||||||||||||||||
22 | 64 | 37 | 439 | 732 | 586 | 461 | 796 | 623 | ||||||||||||||||||||||||||||||||||||||||||||
Expenses |
||||||||||||||||||||||||||||||||||||||||||||||||||||
Transportation and Blending |
1 | 1 | 1 | 17 | 20 | 20 | 18 | 21 | 21 | |||||||||||||||||||||||||||||||||||||||||||
Operating |
15 | 17 | 18 | 175 | 198 | 208 | 190 | 215 | 226 | |||||||||||||||||||||||||||||||||||||||||||
Production and Mineral Taxes |
- | - | - | 2 | 9 | 3 | 2 | 9 | 3 | |||||||||||||||||||||||||||||||||||||||||||
(Gain) Loss on Risk Management |
(4 | ) | - | (4 | ) | (52 | ) | (5 | ) | (61 | ) | (56 | ) | (5 | ) | (65 | ) | |||||||||||||||||||||||||||||||||||
Operating Cash Flow |
10 | 46 | 22 | 297 | 510 | 416 | 307 | 556 | 438 | |||||||||||||||||||||||||||||||||||||||||||
Other | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Oil Sands | Conventional | Total | ||||||||||||||||||||||||||||||||||||||||||||||||||
For the years ended December 31, | 2015 | 2014 | 2013 | 2015 | 2014 | 2013 | 2015 | 2014 | 2013 | |||||||||||||||||||||||||||||||||||||||||||
Revenues |
||||||||||||||||||||||||||||||||||||||||||||||||||||
Gross Sales |
8 | 6 | 24 | 20 | 25 | 13 | 28 | 31 | 37 | |||||||||||||||||||||||||||||||||||||||||||
Less: Royalties |
- | - | - | - | - | - | - | - | - | |||||||||||||||||||||||||||||||||||||||||||
8 | 6 | 24 | 20 | 25 | 13 | 28 | 31 | 37 | ||||||||||||||||||||||||||||||||||||||||||||
Expenses |
||||||||||||||||||||||||||||||||||||||||||||||||||||
Transportation and Blending |
- | - | - | - | - | - | - | - | - | |||||||||||||||||||||||||||||||||||||||||||
Operating |
5 | 7 | 3 | 5 | 6 | 4 | 10 | 13 | 7 | |||||||||||||||||||||||||||||||||||||||||||
Production and Mineral Taxes |
- | - | - | - | - | - | - | - | - | |||||||||||||||||||||||||||||||||||||||||||
(Gain) Loss on Risk Management |
- | - | - | - | - | - | - | - | - | |||||||||||||||||||||||||||||||||||||||||||
Operating Cash Flow |
3 | (1 | ) | 21 | 15 | 19 | 9 | 18 | 18 | 30 | ||||||||||||||||||||||||||||||||||||||||||
Total Upstream | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Oil Sands | Conventional | Total | ||||||||||||||||||||||||||||||||||||||||||||||||||
For the years ended December 31, | 2015 | 2014 | 2013 | 2015 | 2014 | 2013 | 2015 | 2014 | 2013 | |||||||||||||||||||||||||||||||||||||||||||
Revenues |
||||||||||||||||||||||||||||||||||||||||||||||||||||
Gross Sales |
3,030 | 5,036 | 3,912 | 1,709 | 3,225 | 2,980 | 4,739 | 8,261 | 6,892 | |||||||||||||||||||||||||||||||||||||||||||
Less: Royalties |
29 | 236 | 132 | 114 | 229 | 204 | 143 | 465 | 336 | |||||||||||||||||||||||||||||||||||||||||||
3,001 | 4,800 | 3,780 | 1,595 | 2,996 | 2,776 | 4,596 | 7,796 | 6,556 | ||||||||||||||||||||||||||||||||||||||||||||
Expenses |
||||||||||||||||||||||||||||||||||||||||||||||||||||
Transportation and Blending |
1,815 | 2,131 | 1,749 | 230 | 346 | 325 | 2,045 | 2,477 | 2,074 | |||||||||||||||||||||||||||||||||||||||||||
Operating |
531 | 639 | 548 | 561 | 709 | 701 | 1,092 | 1,348 | 1,249 | |||||||||||||||||||||||||||||||||||||||||||
Production and Mineral Taxes |
- | - | - | 18 | 46 | 35 | 18 | 46 | 35 | |||||||||||||||||||||||||||||||||||||||||||
(Gain) Loss on Risk Management |
(404 | ) | (38 | ) | (37 | ) | (209 | ) | (1 | ) | (104 | ) | (613 | ) | (39 | ) | (141 | ) | ||||||||||||||||||||||||||||||||||
Operating Cash Flow |
1,059 | 2,068 | 1,520 | 995 | 1,896 | 1,819 | 2,054 | 3,964 | 3,339 |
Cenovus Energy Inc. | 11 | Consolidated Financial Statements |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2015
C) Geographic Information
Canada | United States | Consolidated | ||||||||||||||||||||||||||||||||||||||||||||||||||
For the years ended December 31, | 2015 | 2014 | 2013 | 2015 | 2014 | 2013 | 2015 | 2014 | 2013 | |||||||||||||||||||||||||||||||||||||||||||
Revenues |
||||||||||||||||||||||||||||||||||||||||||||||||||||
Gross Sales |
6,407 | 10,604 | 8,943 | 6,800 | 9,503 | 10,050 | 13,207 | 20,107 | 18,993 | |||||||||||||||||||||||||||||||||||||||||||
Less: Royalties |
143 | 465 | 336 | - | - | - | 143 | 465 | 336 | |||||||||||||||||||||||||||||||||||||||||||
6,264 | 10,139 | 8,607 | 6,800 | 9,503 | 10,050 | 13,064 | 19,642 | 18,657 | ||||||||||||||||||||||||||||||||||||||||||||
Expenses |
||||||||||||||||||||||||||||||||||||||||||||||||||||
Purchased Product |
1,607 | 2,310 | 2,022 | 5,767 | 8,645 | 8,377 | 7,374 | 10,955 | 10,399 | |||||||||||||||||||||||||||||||||||||||||||
Transportation and Blending |
2,043 | 2,477 | 2,074 | - | - | - | 2,043 | 2,477 | 2,074 | |||||||||||||||||||||||||||||||||||||||||||
Operating |
1,129 | 1,367 | 1,260 | 710 | 678 | 522 | 1,839 | 2,045 | 1,782 | |||||||||||||||||||||||||||||||||||||||||||
Production and Mineral Taxes |
18 | 46 | 35 | - | - | - | 18 | 46 | 35 | |||||||||||||||||||||||||||||||||||||||||||
(Gain) Loss on Risk Management |
(435 | ) | (625 | ) | 275 | (26 | ) | (37 | ) | 18 | (461 | ) | (662 | ) | 293 | |||||||||||||||||||||||||||||||||||||
Depreciation, Depletion and Amortization |
1,925 | 1,790 | 1,695 | 189 | 156 | 138 | 2,114 | 1,946 | 1,833 | |||||||||||||||||||||||||||||||||||||||||||
Goodwill Impairment |
- | 497 | - | - | - | - | - | 497 | - | |||||||||||||||||||||||||||||||||||||||||||
Exploration Expense |
138 | 86 | 114 | - | - | - | 138 | 86 | 114 | |||||||||||||||||||||||||||||||||||||||||||
Segment Income (Loss) |
(161 | ) | 2,191 | 1,132 | 160 | 61 | 995 | (1 | ) | 2,252 | 2,127 |
Export Sales
Sales of crude oil, natural gas and NGLs produced or purchased in Canada that have been delivered to customers outside of Canada were $870 million (2014 $821 million; 2013 $926 million).
Major Customers
In connection with the marketing and sale of Cenovuss own and purchased crude oil, natural gas and refined products for the year ended December 31, 2015, Cenovus had three customers (2014 three; 2013 three) that individually accounted for more than 10 percent of its consolidated gross sales. Sales to these customers, recognized as major international energy companies with investment grade credit ratings, were approximately $4,647 million, $1,705 million and $1,545 million, respectively (2014 $7,210 million, $2,668 million and $2,316 million; 2013 $7,032 million, $2,711 million and $1,799 million), which are included in all of the Companys segments.
D) Exploration and Evaluation Assets, Property, Plant and Equipment, Goodwill and Total Assets
By Segment
E&E (1) | PP&E (2) | Goodwill | Total Assets | |||||||||||||||||||||||||||||||||||||||||||
As at December 31, | 2015 | 2014 | 2015 | 2014 | 2015 | 2014 | 2015 | 2014 | ||||||||||||||||||||||||||||||||||||||
Oil Sands |
1,560 | 1,540 | 8,907 | 8,606 | 242 | 242 | 11,069 | 11,024 | ||||||||||||||||||||||||||||||||||||||
Conventional |
15 | 85 | 3,720 | 6,038 | - | - | 3,830 | 6,211 | ||||||||||||||||||||||||||||||||||||||
Refining and Marketing |
- | - | 4,398 | 3,568 | - | - | 5,844 | 5,520 | ||||||||||||||||||||||||||||||||||||||
Corporate and Eliminations |
- | - | 310 | 351 | - | - | 5,048 | 1,940 | ||||||||||||||||||||||||||||||||||||||
Consolidated |
1,575 | 1,625 | 17,335 | 18,563 | 242 | 242 | 25,791 | 24,695 |
(1) | Exploration and evaluation (E&E) assets. |
(2) | Property, plant and equipment (PP&E). |
Cenovus Energy Inc. | 12 | Consolidated Financial Statements |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2015
By Geographic Region
E&E | PP&E | Goodwill | Total Assets | |||||||||||||||||||||||||||||||||||||||||||
As at December 31, | 2015 | 2014 | 2015 | 2014 | 2015 | 2014 | 2015 | 2014 | ||||||||||||||||||||||||||||||||||||||
Canada |
1,575 | 1,625 | 13,028 | 14,999 | 242 | 242 | 20,627 | 20,231 | ||||||||||||||||||||||||||||||||||||||
United States |
- | - | 4,307 | 3,564 | - | - | 5,164 | 4,464 | ||||||||||||||||||||||||||||||||||||||
Consolidated |
1,575 | 1,625 | 17,335 | 18,563 | 242 | 242 | 25,791 | 24,695 |
E) Capital Expenditures (1)
For the years ended December 31, | 2015 | 2014 | 2013 | |||||||||||||
Capital |
||||||||||||||||
Oil Sands |
1,185 | 1,986 | 1,885 | |||||||||||||
Conventional |
244 | 840 | 1,189 | |||||||||||||
Refining and Marketing |
248 | 163 | 107 | |||||||||||||
Corporate |
37 | 62 | 81 | |||||||||||||
1,714 | 3,051 | 3,262 | ||||||||||||||
Acquisition Capital |
||||||||||||||||
Oil Sands |
3 | 15 | 27 | |||||||||||||
Conventional |
1 | 3 | 5 | |||||||||||||
Refining and Marketing |
83 | - | - | |||||||||||||
1,801 | 3,069 | 3,294 |
(1) | Includes expenditures on PP&E and E&E. |
2. BASIS OF PREPARATION AND STATEMENT OF COMPLIANCE
In these Consolidated Financial Statements, unless otherwise indicated, all dollars are expressed in Canadian dollars. All references to C$ or $ are to Canadian dollars and references to US$ are to U.S. dollars.
These Consolidated Financial Statements have been prepared in accordance with International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB) and interpretations of the International Financial Reporting Interpretations Committee (IFRIC). These Consolidated Financial Statements have been prepared in compliance with IFRS.
These Consolidated Financial Statements have been prepared on a historical cost basis, except as detailed in the Companys accounting policies disclosed in Note 3.
These Consolidated Financial Statements of Cenovus were approved by the Board of Directors on February 10, 2016.
3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A) Principles of Consolidation
The Consolidated Financial Statements include the accounts of Cenovus and its subsidiaries. Subsidiaries are entities over which the Company has control. Subsidiaries are consolidated from the date of acquisition of control and continue to be consolidated until the date that there is a loss of control. All intercompany transactions, balances, and unrealized gains and losses from intercompany transactions are eliminated on consolidation.
Interests in joint arrangements are classified as either joint operations or joint ventures, depending on the rights and obligations of the parties to the arrangement. Joint operations arise when the Company has rights to the assets and obligations for the liabilities of the arrangement. Substantially all of the Companys Oil Sands and Refining activities are conducted through two joint operations, FCCL Partnership (FCCL) and WRB Refining LP (WRB), and accordingly, the accounts reflect the Companys share of the assets, liabilities, revenues and expenses.
Cenovus Energy Inc. | 13 | Consolidated Financial Statements |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2015
B) Foreign Currency Translation
Functional and Presentation Currency
The Companys presentation currency is Canadian dollars. The accounts of the Companys foreign operations that have a functional currency different from the Companys presentation currency are translated into the Companys presentation currency at period-end exchange rates for assets and liabilities, and using average rates over the period for revenues and expenses. Translation gains and losses relating to the foreign operations are recognized in other comprehensive income (OCI) as cumulative translation adjustments.
When the Company disposes of an entire interest in a foreign operation or loses control, joint control, or significant influence over a foreign operation, the foreign currency gains or losses accumulated in OCI related to the foreign operation are recognized in net earnings. When the Company disposes of part of an interest in a foreign operation that continues to be a subsidiary, a proportionate amount of gains and losses accumulated in OCI is allocated between controlling and non-controlling interests.
Transactions and Balances
Transactions in foreign currencies are translated to the respective functional currencies at exchange rates in effect at the dates of the transactions. Monetary assets and liabilities of Cenovus that are denominated in foreign currencies are translated into its functional currency at the rates of exchange in effect at the period-end date. Any gains or losses are recorded in the Consolidated Statements of Earnings.
C) Revenue Recognition
Revenues associated with the sales of Cenovuss crude oil, natural gas, NGLs, and petroleum and refined products are recognized when the significant risks and rewards of ownership have been transferred to the customer, the sales price and costs can be measured reliably and it is probable that the economic benefits will flow to the Company. This is generally met when title passes from the Company to its customer. Revenues from crude oil and natural gas production represent the Companys share, net of royalty payments to governments and other mineral interest owners.
Revenue from fee-for-service hydrocarbon trans-loading services is recognized in the period the service is provided.
Purchases and sales of products that are entered into in contemplation of each other with the same counterparty are recorded on a net basis. Revenues associated with the services provided as agent are recorded as the services are provided.
D) Transportation and Blending
The costs associated with the transportation of crude oil, natural gas and NGLs, including the cost of diluent used in blending, are recognized when the product is sold.
E) Exploration Expense
Costs incurred prior to obtaining the legal right to explore (pre-exploration costs) are expensed in the period in which they are incurred as exploration expense.
Costs incurred after the legal right to explore is obtained, are initially capitalized. If it is determined that the field/project/area is not technically feasible and commercially viable or if the Company decides not to continue the exploration and evaluation activity, the unrecoverable accumulated costs are expensed as exploration expense.
F) Employee Benefit Plans
The Company provides employees with a pension plan that includes either a defined contribution or defined benefit component and an other post-employment benefit plan (OPEB).
Pension expense for the defined contribution pension is recorded as the benefits are earned.
The cost of the defined benefit pension and OPEB plans are actuarially determined using the projected unit credit method. The amount recognized in other liabilities on the Consolidated Balance Sheets for the defined benefit pension and OPEB plans is the present value of the defined benefit obligation less the fair value of plan assets. Any surplus resulting from this calculation is limited to the present value of any economic benefits available in the form of refunds from the plans or reductions in future contributions to the plans.
Cenovus Energy Inc. | 14 | Consolidated Financial Statements |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2015
Changes in the defined benefit obligation from service costs, net interest and remeasurements are recognized as follows:
| Service costs, including current service costs, past service costs, gains and losses on curtailments, and settlements, are recorded with pension benefit costs. |
| Net interest is calculated by applying the same discount rate used to measure the defined benefit obligation at the beginning of the annual period to the net defined benefit asset or liability measured. Interest expense and interest income on net post-employment benefit liabilities and assets are recorded with pension benefit costs in operating, and general and administrative expenses, as well as PP&E and E&E assets. |
| Remeasurements, composed of actuarial gains and losses, the effect of changes to the asset ceiling (excluding interest) and the return on plan assets (excluding interest income), are charged or credited to equity in OCI in the period in which they arise. Remeasurements are not reclassified to net earnings in subsequent periods. |
Pension benefit costs are recorded in operating, and general and administrative expenses, as well as PP&E and E&E assets, corresponding to where the associated salaries of the employees rendering the service are recorded.
G) Income Taxes
Income taxes comprise current and deferred taxes. Income taxes are provided for on a non-discounted basis at amounts expected to be paid using the tax rates and laws that have been enacted or substantively enacted at the Consolidated Balance Sheet date.
Cenovus follows the liability method of accounting for income taxes, where deferred income taxes are recorded for the effect of any temporary difference between the accounting and income tax basis of an asset or liability, using the substantively enacted income tax rates expected to apply when the assets are realized or liabilities are settled. Deferred income tax balances are adjusted to reflect changes in income tax rates that are substantively enacted with the adjustment being recognized in net earnings in the period that the change occurs, except when it relates to items charged or credited directly to equity or OCI, in which case the deferred income tax is also recorded in equity or OCI, respectively.
Deferred income tax is provided on temporary differences arising from investments in subsidiaries except in the case where the timing of the reversal of the temporary difference is controlled by the Company and it is probable that the temporary difference will not reverse in the foreseeable future or when distributions can be made without incurring income taxes.
Deferred income tax assets are recognized only to the extent that it is probable that future taxable profit will be available against which the temporary differences can be utilized. Deferred income tax assets and liabilities are only offset where they arise within the same entity and tax jurisdiction. Deferred income tax assets and liabilities are presented as non-current.
H) Net Earnings per Share Amounts
Basic net earnings per share is computed by dividing net earnings by the weighted average number of common shares outstanding during the period. Diluted net earnings per share is calculated giving effect to the potential dilution that would occur if stock options or other contracts to issue common shares were exercised or converted to common shares. The treasury stock method is used to determine the dilutive effect of stock options and other dilutive instruments. The treasury stock method assumes that proceeds received from the exercise of in-the-money stock options are used to repurchase common shares at the average market price. For those contracts that may be settled in cash or in shares at the holders option, the more dilutive of cash settlement and share settlement is used in calculating diluted earnings per share.
I) Cash and Cash Equivalents
Cash and cash equivalents include short-term investments, such as money market deposits or similar type instruments, with a maturity of three months or less.
J) Inventories
Product inventories are valued at the lower of cost and net realizable value on a first-in, first-out or weighted average cost basis. The cost of inventory includes all costs incurred in the normal course of business to bring each product to its present location and condition. Net realizable value is the estimated selling price in the ordinary course of business less any expected selling costs. If the carrying amount exceeds net realizable value, a write-down is recognized. The write-down may be reversed in a subsequent period if circumstances which caused it no longer exist and the inventory is still on hand.
Cenovus Energy Inc. | 15 | Consolidated Financial Statements |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2015
K) Exploration and Evaluation Assets
Costs incurred after the legal right to explore an area has been obtained, and before technical feasibility and commercial viability of the field/project/area have been established, are capitalized as E&E assets. These costs include license acquisition, geological and geophysical, drilling, sampling, decommissioning and other directly attributable internal costs. E&E assets are not depreciated and are carried forward until technical feasibility and commercial viability of the field/project/area is established or the assets are determined to be impaired. E&E costs are subject to regular technical, commercial and Management review to confirm the continued intent to develop the resources.
Once technical feasibility and commercial viability have been established, the carrying value of the E&E asset is tested for impairment. The carrying value, net of any impairment loss, is then reclassified as PP&E.
Any gains or losses from the divestiture of E&E assets are recognized in net earnings.
L) Property, Plant and Equipment
General
PP&E is stated at cost less accumulated depreciation, depletion and amortization (DD&A), and net impairment losses. Expenditures related to renewals or betterments that improve the productive capacity or extend the life of an asset are capitalized. Maintenance and repairs are expensed as incurred. Land is not depreciated.
Any gains or losses from the divestiture of PP&E are recognized in net earnings.
Development and Production Assets
Development and production assets are capitalized on an area-by-area basis and include all costs associated with the development and production of the crude oil and natural gas properties, as well as any E&E expenditures incurred in finding reserves of crude oil or natural gas transferred from E&E assets. Capitalized costs include directly attributable internal costs, decommissioning liabilities and, for qualifying assets, borrowing costs directly associated with the acquisition of, the exploration for, and the development of crude oil and natural gas reserves.
Costs accumulated within each area are depleted using the unit-of-production method based on estimated proved reserves determined using forward prices and costs. For the purpose of this calculation, natural gas is converted to crude oil on an energy equivalent basis. Costs subject to depletion include estimated future costs to be incurred in developing proved reserves.
Exchanges of development and production assets are measured at fair value unless the transaction lacks commercial substance or the fair value of neither the asset received, nor the asset given up, can be reliably measured. When fair value is not used, the carrying amount of the asset given up is used as the cost of the asset acquired.
Other Upstream Assets
Other upstream assets include pipelines and information technology assets used to support the upstream business. These assets are depreciated on a straight-line basis over their useful lives of three to 35 years.
Refining Assets
The initial acquisition costs of refining PP&E are capitalized when incurred. Costs include the cost of constructing or otherwise acquiring the equipment or facilities, the cost of installing the asset and making it ready for its intended use, the associated decommissioning costs and, for qualifying assets, borrowing costs.
Refining assets are depreciated on a straight-line basis over the estimated service life of each component of the refinery. The major components are depreciated as follows:
Land Improvements and Buildings | 25 to 40 years | |||
Office Equipment and Vehicles | 3 to 20 years | |||
Refining Equipment | 5 to 35 years |
The residual value, method of amortization and the useful life of each component are reviewed annually and adjusted on a prospective basis, if appropriate.
Cenovus Energy Inc. | 16 | Consolidated Financial Statements |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2015
Other Assets
Costs associated with the crude-by-rail terminal, office furniture, fixtures, leasehold improvements, information technology and aircraft are carried at cost and depreciated on a straight-line basis over the estimated service lives of the assets, which range from three to 40 years.
The residual value, method of amortization and the useful lives of the assets are reviewed annually and adjusted on a prospective basis, if appropriate.
M) Impairment
Non-Financial Assets
PP&E and E&E assets are reviewed separately for indicators of impairment quarterly or when facts and circumstances suggest that the carrying amount may exceed its recoverable amount. Goodwill is tested for impairment at least annually.
If indicators of impairment exist, the recoverable amount of the cash-generating unit (CGU) is estimated as the greater of value-in-use (VIU) and fair value less costs of disposal (FVLCOD). VIU is estimated as the discounted present value of the future cash flows expected to arise from the continuing use of a CGU or an asset. FVLCOD is determined by estimating the discounted after-tax future net cash flows. For Cenovuss upstream assets, FVLCOD is based on the discounted after-tax cash flows of reserves and resources using forward prices and costs, consistent with Cenovuss independent qualified reserves evaluators, and may consider an evaluation of comparable asset transactions.
If the recoverable amount of the CGU is less than the carrying amount, an impairment loss is recognized. An impairment loss is allocated first to reduce the carrying amount of any goodwill allocated to the CGU and then to reduce the carrying amounts of the other assets in the CGU. Goodwill impairments are not reversed.
E&E assets are allocated to a related CGU containing development and production assets for the purposes of testing for impairment. Goodwill is allocated to the CGUs to which it contributes to the future cash flows.
Impairment losses on PP&E and E&E assets are recognized in the Consolidated Statements of Earnings as additional DD&A and exploration expense, respectively.
Impairment losses recognized in prior periods, other than goodwill impairments, are assessed at each reporting date for any indicators that the impairment losses may no longer exist or may have decreased. In the event that an impairment loss reverses, the carrying amount of the asset is increased to the revised estimate of its recoverable amount, but only to the extent that the carrying amount does not exceed the amount that would have been determined had no impairment loss been recognized on the asset in prior periods. The amount of the reversal is recognized in net earnings.
Financial Assets
At each reporting date, the Company assesses whether there are any indicators that its financial assets are impaired. An impairment loss is only recognized if there is objective evidence of impairment, the loss event has an impact on future cash flows and the loss can be reliably estimated.
Evidence of impairment may include default or delinquency by a debtor or indicators that the debtor may enter bankruptcy. For equity securities, a significant or prolonged decline in the fair value of the security below cost is evidence that the assets are impaired.
An impairment loss on a financial asset carried at amortized cost is calculated as the difference between the amortized cost and the present value of the future cash flows discounted at the assets original effective interest rate. The carrying amount of the asset is reduced through the use of an allowance account. Impairment losses on financial assets carried at amortized cost are reversed through net earnings in subsequent periods if the amount of the loss decreases.
N) Leases
Leases in which substantially all of the risks and rewards of ownership are retained by the lessor are classified as operating leases. Operating lease payments are recognized as an expense on a straight-line basis over the lease term.
Leases where the Company assumes substantially all the risks and rewards of ownership are classified as finance leases within PP&E.
Cenovus Energy Inc. | 17 | Consolidated Financial Statements |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2015
O) Business Combinations and Goodwill
Business combinations are accounted for using the acquisition method of accounting in which the identifiable assets acquired, liabilities assumed and any non-controlling interest are recognized and measured at their fair value at the date of acquisition. Any excess of the purchase price plus any non-controlling interest over the fair value of the net assets acquired is recognized as goodwill. Any deficiency of the purchase price over the fair value of the net assets acquired is credited to net earnings.
At acquisition, goodwill is allocated to each of the CGUs to which it relates. Subsequent measurement of goodwill is at cost less any accumulated impairment losses.
P) Provisions
General
A provision is recognized if, as a result of a past event, the Company has a present obligation, legal or constructive, that can be estimated reliably, and it is more likely than not that an outflow of economic benefits will be required to settle the obligation. Where applicable, provisions are determined by discounting the expected future cash flows at a pre-tax credit-adjusted rate that reflects the current market assessments of the time value of money and the risks specific to the liability. The increase in the provision due to the passage of time is recognized as a finance cost in the Consolidated Statements of Earnings.
Decommissioning Liabilities
Decommissioning liabilities include those legal or constructive obligations where the Company will be required to retire tangible long-lived assets such as producing well sites, crude oil and natural gas processing facilities, refining facilities and the crude-by-rail terminal. The amount recognized is the present value of estimated future expenditures required to settle the obligation using a credit-adjusted risk-free rate. A corresponding asset equal to the initial estimate of the liability is capitalized as part of the cost of the related long-lived asset. Changes in the estimated liability resulting from revisions to expected timing or future decommissioning costs are recognized as a change in the decommissioning liability and the related long-lived asset. The amount capitalized in PP&E is depreciated over the useful life of the related asset.
Actual expenditures incurred are charged against the accumulated liability.
Q) Share Capital
Common shares are classified as equity. Transaction costs directly attributable to the issue of common shares are recognized as a deduction from equity, net of any income taxes.
R) Stock-Based Compensation
Cenovus has a number of stock-based compensation plans which include stock options with associated net settlement rights (NSRs), stock options with associated tandem stock appreciation rights (TSARs), performance share units (PSUs), restricted share units (RSUs) and deferred share units (DSUs). Stock-based compensation costs are recorded in general and administrative expense, or E&E and PP&E when directly related to exploration or development activities.
Net Settlement Rights
NSRs are accounted for as equity instruments, which are measured at fair value on the grant date using the Black-Scholes-Merton valuation model and are not revalued at each reporting date. The fair value is recognized as stock-based compensation costs over the vesting period, with a corresponding increase recorded as paid in surplus in Shareholders Equity. On exercise, the cash consideration received by the Company and the associated paid in surplus are recorded as share capital.
Tandem Stock Appreciation Rights
TSARs are accounted for as liability instruments, which are measured at fair value at each period end using the Black-Scholes-Merton valuation model. The fair value is recognized as stock-based compensation costs over the vesting period. When options are settled for cash, the liability is reduced by the cash settlement paid. When options are settled for common shares, the cash consideration received by the Company and the previously recorded liability associated with the option are recorded as share capital.
Cenovus Energy Inc. | 18 | Consolidated Financial Statements |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2015
Performance, Restricted and Deferred Share Units
PSUs, RSUs and DSUs are accounted for as liability instruments and are measured at fair value based on the market value of Cenovuss common shares at each period end. The fair value is recognized as stock-based compensation costs over the vesting period. Fluctuations in the fair values are recognized as stock-based compensation costs in the period they occur.
S) Financial Instruments
The Companys financial assets include cash and cash equivalents, accounts receivable and accrued revenues, risk management assets, available for sale financial assets and long-term receivables. The Companys financial liabilities include accounts payable and accrued liabilities, risk management liabilities, short-term borrowings and long-term debt.
Financial instruments are recognized when the Company becomes a party to the contractual provisions of the instrument. Financial assets and liabilities are not offset unless the Company has the current legal right to offset and intends to settle on a net basis or settle the asset and liability simultaneously. A financial asset is derecognized when the rights to receive cash flows from the asset have expired or have been transferred and the Company has transferred substantially all the risks and rewards of ownership. A financial liability is derecognized when the obligation is discharged, cancelled or expired. When an existing financial liability is replaced by another from the same counterparty with substantially different terms, or the terms of an existing liability are substantially modified, this exchange or modification is treated as a derecognition of the original liability and the recognition of a new liability. The difference in the carrying amounts of the liabilities is recognized in the Consolidated Statements of Earnings.
Financial instruments are classified as either fair value through profit and loss, loans and receivables, held-to-maturity investments, available for sale financial assets or financial liabilities measured at amortized cost. The Company determines the classification of its financial assets at initial recognition. Financial instruments are initially measured at fair value except in the case of financial liabilities measured at amortized cost, which are initially measured at fair value net of directly attributable transaction costs.
As required by IFRS, the Company characterizes its fair value measurements into a three-level hierarchy depending on the degree to which the inputs are observable, as follows:
| Level 1 inputs are quoted prices in active markets for identical assets and liabilities; |
| Level 2 inputs are inputs, other than quoted prices included within Level 1, that are observable for the asset or liability either directly or indirectly; and |
| Level 3 inputs are unobservable inputs for the asset or liability. |
Fair Value through Profit or Loss
Financial assets and financial liabilities at fair value through profit or loss are either held-for-trading or have been designated at fair value through profit or loss. In both cases, the financial assets and financial liabilities are measured at fair value with changes in fair value recognized in net earnings.
Risk management assets and liabilities are derivative financial instruments classified as held-for-trading unless designated for hedge accounting. Derivative instruments that do not qualify as hedges, or are not designated as hedges, are recorded using mark-to-market accounting whereby instruments are recorded in the Consolidated Balance Sheets as either an asset or liability with changes in fair value recognized in net earnings as a (gain) loss on risk management. The estimated fair value of all derivative instruments is based on quoted market prices or, in their absence, third-party market indications and forecasts.
Derivative financial instruments are used to manage economic exposure to market risks relating to commodity prices, foreign currency exchange rates and interest rates. Derivative financial instruments are not used for speculative purposes. Policies and procedures are in place with respect to required documentation and approvals for the use of derivative financial instruments. Where specific financial instruments are executed, the Company assesses, both at the time of purchase and on an ongoing basis, whether the financial instrument used in the particular transaction is effective in offsetting changes in fair values or cash flows of the transaction.
Loans and Receivables
Loans and receivables are financial assets with fixed or determinable payments that are not quoted in an active market. After initial measurement, these assets are measured at amortized cost at the settlement date using the effective interest method of amortization. Loans and receivables comprise cash and cash equivalents, accounts receivable and accrued revenues, and long-term receivables. Gains and losses on loans and receivables are recognized in net earnings when the loans and receivables are derecognized or impaired.
Cenovus Energy Inc. | 19 | Consolidated Financial Statements |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2015
Available for Sale Financial Assets
Available for sale financial assets are measured at fair value, with changes in the fair value recognized in OCI. When an active market is non-existent, fair value is determined using valuation techniques. When fair value cannot be reliably measured, such assets are carried at cost. Available for sale financial assets comprise investments in the equity of private companies that the Company does not control or have significant influence over.
Financial Liabilities Measured at Amortized Cost
These financial liabilities are measured at amortized cost at the settlement date using the effective interest method of amortization. Financial liabilities measured at amortized cost comprise accounts payable and accrued liabilities, short-term borrowings and long-term debt. Long-term debt transaction costs, premiums and discounts are capitalized within long-term debt or as a prepayment and amortized using the effective interest method.
T) Reclassification
Certain information provided for prior years has been reclassified to conform to the presentation adopted in 2015. Employee stock-based compensation costs previously included in operating expense have been reclassified to general and administrative expense. As a result, for the years ended December 31, 2014 and 2013, expenses of $21 million and $16 million, respectively, were reclassified.
U) Recent Accounting Pronouncements
New and Amended Accounting Standards and Interpretations Adopted
There were no new or amended accounting standards or interpretations adopted during the year ended December 31, 2015.
New Accounting Standards and Interpretations not yet Adopted
A number of new accounting standards, amendments to accounting standards and interpretations are effective for annual periods beginning on or after January 1, 2016 and have not been applied in preparing the Consolidated Financial Statements for the year ended December 31, 2015. The standards applicable to the Company are as follows and will be adopted on their respective effective dates:
Leases
On January 13, 2016, the IASB issued IFRS 16, Leases (IFRS 16), which requires entities to recognize lease assets and lease obligations on the balance sheet. For lessees, IFRS 16 removes the classification of leases as either operating leases or finance leases, effectively treating all leases as finance leases. Certain short-term leases (less than 12 months) and leases of low-value assets are exempt from the requirements, and may continue to be treated as operating leases.
Lessors will continue with a dual lease classification model. Classification will determine how and when a lessor will recognize lease revenue, and what assets would be recorded.
IFRS 16 is effective for years beginning on or after January 1, 2019, with early adoption permitted if IFRS 15 Revenue From Contracts With Customers has been adopted. The standard may be applied retrospectively or using a modified retrospective approach. The Company is currently evaluating the impact of adopting IFRS 16 on the Consolidated Financial Statements.
Revenue Recognition
On May 28, 2014, the IASB issued IFRS 15, Revenue From Contracts With Customers (IFRS 15) replacing IAS 11, Construction Contracts, IAS 18, Revenue and several revenue-related interpretations. IFRS 15 establishes a single revenue recognition framework that applies to contracts with customers. The standard requires an entity to recognize revenue to reflect the transfer of goods and services for the amount it expects to receive, when control is transferred to the purchaser. Disclosure requirements have also been expanded.
IFRS 15 is effective for annual periods beginning on or after January 1, 2018. Early adoption is permitted. The standard may be applied retrospectively or using a modified retrospective approach. The Company is currently evaluating the impact of adopting IFRS 15 on the Consolidated Financial Statements.
Financial Instruments
On July 24, 2014, the IASB issued the final version of IFRS 9, Financial Instruments (IFRS 9) to replace IAS 39, Financial Instruments: Recognition and Measurement (IAS 39).
IFRS 9 introduces a single approach to determine whether a financial asset is measured at amortized cost or fair value and replaces the multiple rules in IAS 39. The approach is based on how an entity manages its financial instruments in the context of its business model and the contractual cash flow characteristics of the financial
Cenovus Energy Inc. | 20 | Consolidated Financial Statements |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2015
assets. For financial liabilities, IFRS 9 retains most of the IAS 39 requirements; however, where the fair value option is applied to financial liabilities, the change in fair value resulting from an entitys own credit risk is recorded in OCI rather than net earnings, unless this creates an accounting mismatch. In addition, a new expected credit loss model for calculating impairment on financial assets replaces the incurred loss impairment model used in IAS 39. The new model will result in more timely recognition of expected credit losses. IFRS 9 also includes a simplified hedge accounting model, aligning hedge accounting more closely with risk management. Cenovus does not currently apply hedge accounting.
IFRS 9 is effective for years beginning on or after January 1, 2018. Early adoption is permitted if IFRS 9 is adopted in its entirety at the beginning of a fiscal period. The Company is currently evaluating the impact of adopting IFRS 9 on the Consolidated Financial Statements.
4. CRITICAL ACCOUNTING JUDGMENTS AND KEY SOURCES OF ESTIMATION UNCERTAINTY
The timely preparation of the Consolidated Financial Statements in accordance with IFRS requires that Management make estimates and assumptions, and use judgment regarding the reported amounts of assets and liabilities, and disclosures of contingent assets and liabilities at the date of the Consolidated Financial Statements, and the reported amounts of revenues and expenses during the period. Such estimates primarily relate to unsettled transactions and events as of the date of the Consolidated Financial Statements. The estimated fair value of financial assets and liabilities, by their very nature, are subject to measurement uncertainty. Accordingly, actual results may differ from estimated amounts as future confirming events occur.
A) Critical Judgments in Applying Accounting Policies
Critical judgments are those judgments made by Management in the process of applying accounting policies that have the most significant effect on the amounts recorded in the Companys Consolidated Financial Statements.
Joint Arrangements
Cenovus holds a 50 percent ownership interest in two jointly controlled entities, FCCL and WRB. The classification of these joint arrangements as either a joint operation or a joint venture requires judgment. It was determined that Cenovus has the rights to the assets and obligations for the liabilities of FCCL and WRB.
As a result, these joint arrangements are classified as joint operations and the Companys share of the assets, liabilities, revenues and expenses are recorded in the Consolidated Financial Statements.
In determining the classification of its joint arrangements under IFRS 11, Joint Arrangements, the Company considered the following:
| The intention of the transaction creating FCCL and WRB was to form an integrated North American heavy oil business. The integrated business was structured, initially on a tax neutral basis, through two partnerships due to the assets residing in different tax jurisdictions. Partnerships are flow-through entities which have a limited life. |
| The partnership agreements require the partners (Cenovus and ConocoPhillips or Phillips 66 or respective subsidiaries) to make contributions if funds are insufficient to meet the obligations or liabilities of the partnership. The past and future development of FCCL and WRB is dependent on funding from the partners by way of partnership notes payable and loans. The partnerships do not have any third-party borrowings. |
| FCCL operates like most typical western Canadian working interest relationships where the operating partner takes product on behalf of the participants. WRB has a very similar structure modified only to account for the operating environment of the refining business. |
| Cenovus and Phillips 66, as operators, either directly or through wholly-owned subsidiaries, provide marketing services, purchase necessary feedstock, and arrange for transportation and storage on the partners behalf as the agreements prohibit the partnerships from undertaking these roles themselves. In addition, the partnerships do not have employees and, as such, are not capable of performing these roles. |
| In each arrangement, output is taken by one of the partners, indicating that the partners have rights to the economic benefits of the assets and the obligation for funding the liabilities of the arrangements. |
Cenovus Energy Inc. | 21 | Consolidated Financial Statements |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2015
Exploration and Evaluation Assets
The application of the Companys accounting policy for E&E expenditures requires judgment in determining whether it is likely that future economic benefit exists when activities have not reached a stage where technical feasibility and commercial viability can be reasonably determined. Factors such as drilling results, future capital programs, future operating expenses, as well as estimated reserves and resources are considered. In addition, Management uses judgment to determine when E&E assets are reclassified to PP&E. In making this determination, various factors are considered, including the existence of reserves, and whether the appropriate approvals have been received from regulatory bodies and the Companys internal approval process.
Identification of CGUs
CGUs are defined as the lowest level of integrated assets for which there are separately identifiable cash flows that are largely independent of cash flows from other assets or groups of assets. The classification of assets and allocation of corporate assets into CGUs requires significant judgment and interpretations. Factors considered in the classification include the integration between assets, shared infrastructures, the existence of common sales points, geography, geologic structure, and the manner in which Management monitors and makes decisions about its operations. The recoverability of the Companys upstream, refining, crude-by-rail and corporate assets are assessed at the CGU level. As such, the determination of a CGU could have a significant impact on impairment losses.
B) Key Sources of Estimation Uncertainty
Critical accounting estimates are those estimates that require Management to make particularly subjective or complex judgments about matters that are inherently uncertain. Estimates and underlying assumptions are reviewed on an ongoing basis and any revisions to accounting estimates are recorded in the period in which the estimates are revised. The following are the key assumptions about the future and other key sources of estimation at the end of the reporting period that changes to could result in a material adjustment to the carrying amount of assets and liabilities within the next financial year.
Crude Oil and Natural Gas Reserves
There are a number of inherent uncertainties associated with estimating crude oil and natural gas reserves. Reserves estimates are dependent upon variables including the recoverable quantities of hydrocarbons, the cost of the development of the required infrastructure to recover the hydrocarbons, production costs, estimated selling price of the hydrocarbons produced, royalty payments and taxes. Changes in these variables could significantly impact the reserves estimates which would affect the impairment test and DD&A expense of the Companys crude oil and natural gas assets in the Oil Sands and Conventional segments. The Companys crude oil and natural gas reserves are evaluated annually and reported to the Company by independent qualified reserves evaluators.
Impairment of Assets
Determining the recoverable amount of a CGU or an individual asset requires the use of estimates and assumptions, which are subject to change as new information becomes available. For the Companys upstream assets, these estimates include forward commodity prices, expected production volumes, quantity of reserves and resources, discount rates, future development and operating expenses, and income tax rates. Recoverable amounts for the Companys refining assets and crude-by-rail terminal use assumptions such as throughput, forward commodity prices, operating expenses, transportation capacity, supply and demand conditions and income tax rates. Changes in assumptions used in determining the recoverable amount could affect the carrying value of the related assets.
Decommissioning Costs
Provisions are recorded for the future decommissioning and restoration of the Companys upstream crude oil and natural gas assets, refining assets and crude-by-rail terminal at the end of their economic lives. Management uses judgement to assess the existence and to estimate the future liability. The actual cost of decommissioning and restoration is uncertain and cost estimates may change in response to numerous factors including changes in legal requirements, technological advances, inflation and the timing of expected decommissioning and restoration. In addition, Management determines the appropriate discount rate at the end of each reporting period. This discount rate, which is credit adjusted, is used to determine the present value of the estimated future cash outflows required to settle the obligation and may change in response to numerous market factors.
Cenovus Energy Inc. | 22 | Consolidated Financial Statements |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2015
Income Tax Provisions
Tax regulations and legislation and the interpretations thereof in the various jurisdictions in which Cenovus operates are subject to change. There are usually a number of tax matters under review; therefore, income taxes are subject to measurement uncertainty.
Deferred income tax assets are recorded to the extent that it is probable that the deductible temporary differences will be recoverable in future periods. The recoverability assessment involves a significant amount of estimation including an evaluation of when the temporary differences will reverse, an analysis of the amount of future taxable earnings, the availability of cash flow to offset the tax assets when the reversal occurs and the application of tax laws. There are some transactions for which the ultimate tax determination is uncertain. To the extent that assumptions used in the recoverability assessment change, there may be a significant impact on the Consolidated Financial Statements of future periods.
For the years ended December 31, | 2015 | 2014 | 2013 | |||||||||||||
Interest Expense Short-Term Borrowings and Long-Term Debt |
328 | 285 | 271 | |||||||||||||
Premium on Redemption of Long-Term Debt |
- | - | 33 | |||||||||||||
Unwinding of Discount on Decommissioning Liabilities (Note 22) |
126 | 120 | 97 | |||||||||||||
Other |
28 | 18 | 30 | |||||||||||||
Interest Expense Partnership Contribution Payable (1) |
- | 22 | 98 | |||||||||||||
482 | 445 | 529 |
(1) | In 2014, Cenovus repaid the remaining principal and accrued interest due under the Partnership Contribution Payable. |
For the years ended December 31, | 2015 | 2014 | 2013 | |||||||||||||
Interest Income Partnership Contribution Receivable (1) |
- | - | (82 | ) | ||||||||||||
Other |
(28 | ) | (33 | ) | (14 | ) | ||||||||||
(28 | ) | (33 | ) | (96 | ) |
(1) | In 2013, Cenovus received the remaining principal and accrued interest due under the Partnership Contribution Receivable. |
7. FOREIGN EXCHANGE (GAIN) LOSS, NET
For the years ended December 31, | 2015 | 2014 | 2013 | |||||||||||||
Unrealized Foreign Exchange (Gain) Loss on Translation of: |
||||||||||||||||
U.S. Dollar Debt Issued From Canada |
1,064 | 458 | 357 | |||||||||||||
U.S. Dollar Partnership Contribution Receivable Issued From Canada |
- | - | (305 | ) | ||||||||||||
Other |
33 | (47 | ) | (12 | ) | |||||||||||
Unrealized Foreign Exchange (Gain) Loss |
1,097 | 411 | 40 | |||||||||||||
Realized Foreign Exchange (Gain) Loss |
(61 | ) | - | 168 | ||||||||||||
1,036 | 411 | 208 |
Cenovus Energy Inc. | 23 | Consolidated Financial Statements |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2015
On July 29, 2015, the Company completed the sale of Heritage Royalty Limited Partnership (HRP), a wholly-owned subsidiary, to a third party for gross cash proceeds of $3.3 billion, resulting in a gain of $2.4 billion. HRP is a royalty business consisting of approximately 4.8 million gross acres of royalty interest and mineral fee title lands in Alberta, Saskatchewan and Manitoba. Cenovus entered into lease agreements with HRP on the fee lands from which it currently has working interest production.
In addition, HRP has a Gross Overriding Royalty on production from Cenovuss Pelican Lake and Weyburn assets. These assets and results of operations were reported in the Conventional segment.
The divestiture gave rise to a taxable gain for which the Company has recognized current tax expense of $391 million. The majority of HRPs assets had been acquired at a nominal cost and, as such, had minimal benefit from tax depreciation in prior years. For this reason, the current tax expense associated with the divestiture is specifically identifiable; therefore, it has been classified as an investing activity in the Consolidated Statements of Cash Flows.
In the first quarter of 2015, the Company divested an office building, recording a gain of $16 million.
In 2014, the Company completed the sale of certain Wainwright properties to an unrelated third party for net proceeds of $234 million, resulting in a gain of $137 million. The Company also completed the sale of certain Bakken properties to an unrelated third party for net proceeds of $35 million, resulting in a gain of $16 million. Other divestitures in 2014 included the sale of certain non-core properties, resulting in a gain of $4 million. These assets and results of operations were reported in the Conventional segment.
In 2013, the Company completed the sale of the Lower Shaunavon asset to an unrelated third party for net proceeds of $241 million, resulting in a loss of $2 million. These assets and results of operations were reported in the Conventional segment. Other divestitures in 2013 included undeveloped land in northern Alberta, cancellation of some of the Companys non-core Oil Sands mineral rights under the Lower Athabasca Regional Plan and a third-party land exchange.
A) Cash-Generating Unit Impairments
As indicators of impairment were noted due to the significant decline in forward commodity prices, the Company has tested its upstream CGUs for impairment.
Key Assumptions
As at December 31, 2015, the recoverable amounts of Cenovuss upstream CGUs were determined based on fair value less costs of disposal or an evaluation of comparable asset transactions. Key assumptions in the determination of future cash flows from reserves include crude oil and natural gas prices, costs to develop and the discount rate. All reserves have been evaluated as at December 31, 2015 by independent qualified reserves evaluators.
Crude Oil and Natural Gas Prices
The forward prices used to determine future cash flows from crude oil and natural gas reserves are:
2016 | 2017 | 2018 | 2019 | 2020 | Average Annual % Change to 2026 |
|||||||||||||||||||
|
||||||||||||||||||||||||
WTI (US$/barrel) (1) |
45.00 | 53.60 | 62.40 | 69.00 | 73.10 | 3.8% | ||||||||||||||||||
WCS (C$/barrel) (2) |
46.40 | 54.40 | 59.70 | 66.30 | 68.20 | 3.9% | ||||||||||||||||||
AECO (C$/Mcf) (3) (4) |
2.70 | 3.20 | 3.55 | 3.85 | 3.95 | 4.0% | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
(1) | West Texas Intermediate (WTI) crude oil. |
(2) | Western Canadian Select (WCS) crude oil blend. |
(3) | Alberta Energy Company (AECO) natural gas. |
(4) | Assumes gas heating value of one million British Thermal Units per thousand cubic feet. |
Cenovus Energy Inc. | 24 | Consolidated Financial Statements |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2015
Discount and Inflation Rates
Evaluations of discounted future cash flows are initiated using the discount rate of 10 percent and inflation is estimated at two percent, which is common industry practice and used by Cenovuss independent qualified reserves evaluators in preparing their reserves reports. Based on the individual characteristics of the asset, other economic and operating factors are also considered, which may increase or decrease the implied discount rate.
2015 Impairments
As at December 31, 2015, the Company determined that the carrying amount of the Northern Alberta CGU exceeded its recoverable amount, resulting in an impairment loss of $184 million. The impairment was recorded as additional DD&A in the Conventional segment. The Northern Alberta CGU includes the Pelican Lake and Elk Point producing assets and other emerging assets in the exploration and evaluation stage. Future cash flows for the CGU declined due to lower forward crude oil prices, a decline in reserves estimates and a slowing down of the development plan. This was partially offset by lower future development and operating costs.
The recoverable amount was determined using fair value less costs of disposal. The fair value for producing properties was calculated based on discounted after-tax cash flows of proved and probable reserves using forward prices and cost estimates, consistent with Cenovuss independent qualified reserves evaluators (Level 3). Future cash flows were estimated using a two percent inflation rate and discounted using a rate of 10 percent. As at December 31, 2015, the recoverable amount of the Northern Alberta CGU was estimated to be approximately $1.5 billion.
For the purpose of impairment testing, goodwill is allocated to the CGU to which it relates. There were no impairments of goodwill in the year ended December 31, 2015.
Sensitivities
Changes to the assumed discount rate or forward price estimates over the life of the reserves independently would have the following impact on the 2015 impairment of the Northern Alberta CGU:
One Percent Increase in the Discount Rate |
Five Percent Decrease in the Forward Price Estimates |
|||||||||
Increase to Impairment of PP&E |
157 | 336 |
2014 Impairments
As at December 31, 2014, the Company determined that the carrying amount of the Northern Alberta CGU exceeded its recoverable amount and the full amount of the impairment was attributed to goodwill. An impairment loss of $497 million was recorded as goodwill impairment on the Consolidated Statements of Earnings. The operating results of the CGU are included in the Conventional segment. Future cash flows for the CGU declined due to lower crude oil prices and a slowing down of the Pelican Lake development plan.
The recoverable amount was determined using fair value less costs of disposal. The fair value for producing properties was calculated based on discounted after-tax cash flows of proved and probable reserves using forward prices and cost estimates, consistent with Cenovuss independent qualified reserves evaluators (Level 3). The fair value of E&E assets was determined using market comparable transactions (Level 3). Future cash flows were estimated using a two percent inflation rate and discounted using a rate of 11 percent. To assess reasonableness, an evaluation of fair value based on comparable asset transactions was also completed. As at December 31, 2014, the recoverable amount of the Northern Alberta CGU was estimated to be $2.3 billion.
2013 Impairments
There were no CGU impairments for the year ended December 31, 2013.
B) Asset Impairments
Exploration and Evaluation Assets
In 2015, $138 million of previously capitalized E&E costs were deemed not to be technically feasible and commercially viable, and were recorded as exploration expense. This impairment loss included $67 million and $71 million within the Oil Sands and Conventional segments, respectively.
Cenovus Energy Inc. | 25 | Consolidated Financial Statements |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2015
In 2014, $82 million of previously capitalized E&E costs were deemed not to be technically feasible and commercially viable, and were recorded as exploration expense in the Conventional segment. In addition, $4 million of costs related to the expiry of leases in the Borealis CGU were recorded as exploration expense in the Oil Sands segment.
In 2013, $50 million of previously capitalized E&E costs were deemed not to be technically feasible and commercially viable and were recorded as exploration expense in the Conventional segment.
Property, Plant and Equipment, Net
In addition to the impairments recorded at the CGU level, DD&A expense includes the following asset impairments:
For the years ended December 31, | 2015 | 2014 | 2013 | |||||||||||||
Development and Production (Note 16) |
16 | 65 | 59 | |||||||||||||
16 | 65 | 59 |
In 2015, the Company impaired a sulphur recovery facility for $16 million, which was recorded in the Oil Sands segment. The Company did not have future plans for the assets and did not believe it would recover the carrying amount through a sale.
In 2014, the Company impaired equipment for $52 million. The Company did not have future plans for the equipment and did not believe it would recover the carrying amount through a sale. The asset was written down to fair value less costs of disposal. Additionally, a minor natural gas property was shut-in and abandonment commenced, resulting in an impairment of $13 million. These impairments were recorded in the Conventional segment.
In 2013, the Company impaired its Lower Shaunavon asset for $57 million prior to its divestiture. The impairment was recorded in the Conventional segment.
The provision for income taxes is:
For the years ended December 31, | 2015 | 2014 | 2013 | |||||||||||||
Current Tax |
||||||||||||||||
Canada |
586 | 94 | 143 | |||||||||||||
United States |
(12 | ) | (2 | ) | 45 | |||||||||||
Total Current Tax Expense (Recovery) |
574 | 92 | 188 | |||||||||||||
Deferred Tax Expense (Recovery) |
(655 | ) | 359 | 244 | ||||||||||||
(81 | ) | 451 | 432 |
In 2015, the Company recorded a deferred tax recovery of $415 million arising from an adjustment to the tax basis of the Companys refining assets. The increase in tax basis was a result of the Companys partner recognizing a taxable gain on its interest in WRB which, due to an election filed with the U.S. tax authorities, was added to the tax basis of WRBs assets.
The Alberta government enacted a two percent increase in the corporate income tax rate effective July 1, 2015, increasing the statutory tax rate for the year to 26.1 percent. As a result, the Companys deferred income tax liability increased by $161 million for the year ended December 31, 2015. The Canadian statutory tax rate as at December 31, 2015 was 27.0 percent. The U.S. statutory tax rate has decreased to 38.0 percent from 38.1 percent in 2014 and 38.5 percent in 2013.
Cenovus Energy Inc. | 26 | Consolidated Financial Statements |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2015
The following table reconciles income taxes calculated at the Canadian statutory rate with the recorded income taxes:
For the years ended December 31, | 2015 | 2014 | 2013 | |||||||||||||
Earnings Before Income Tax |
537 | 1,195 | 1,094 | |||||||||||||
Canadian Statutory Rate |
26.1% | 25.2% | 25.2% | |||||||||||||
Expected Income Tax |
140 | 301 | 276 | |||||||||||||
Effect of Taxes Resulting From: |
||||||||||||||||
Foreign Tax Rate Differential |
(41) | (43) | 87 | |||||||||||||
Non-Deductible Stock-Based Compensation |
7 | 13 | 10 | |||||||||||||
Non-Taxable Capital Losses |
137 | 74 | 6 | |||||||||||||
Unrecognized Capital Losses Arising From Unrealized Foreign Exchange |
135 | 50 | 25 | |||||||||||||
Adjustments Arising From Prior Year Tax Filings |
(55) | (16) | (13) | |||||||||||||
Derecognition (Recognition) of Capital Losses |
(149) | (9) | 15 | |||||||||||||
Recognition of U.S. Tax Basis |
(415) | - | - | |||||||||||||
Change in Statutory Rate |
161 | - | - | |||||||||||||
Foreign Exchange Gains (Losses) not Included in Net Earnings |
- | (13) | 19 | |||||||||||||
Goodwill Impairment |
- | 125 | - | |||||||||||||
Other |
(1) | (31) | 7 | |||||||||||||
Total Tax |
(81) | 451 | 432 | |||||||||||||
Effective Tax Rate |
(15.1)% | 37.7% | 39.5% | |||||||||||||
The analysis of deferred income tax liabilities and deferred income tax assets is: |
||||||||||||||||
As at December 31, | 2015 | 2014 | ||||||||||||||
Net Deferred Income Tax Liabilities |
||||||||||||||||
Deferred Tax Liabilities to be Settled Within 12 Months |
58 | 296 | ||||||||||||||
Deferred Tax Liabilities to be Settled After More Than 12 Months |
2,758 | 3,006 | ||||||||||||||
2,816 | 3,302 |
For the purposes of the preceding table, deferred income tax liabilities are shown net of offsetting deferred income tax assets where they occur in the same entity and jurisdiction. The deferred income tax liabilities to be settled within 12 months represents Managements estimate of the timing of the reversal of temporary differences and may not correlate to the current income tax expense of the subsequent year.
The movement in deferred income tax liabilities and assets, without taking into consideration the offsetting of balances within the same tax jurisdiction, is:
Deferred Income Tax Liabilities | Property, Plant and Equipment |
Timing of Partnership Items |
Risk Management |
Other | Total | |||||||||||||||||||||||
As at December 31, 2013 |
3,000 | 88 | 2 | 152 | 3,242 | |||||||||||||||||||||||
Charged/(Credited) to Earnings |
22 | 79 | 119 | (111 | ) | 109 | ||||||||||||||||||||||
Charged/(Credited) to OCI |
84 | - | - | - | 84 | |||||||||||||||||||||||
As at December 31, 2014 |
3,106 | 167 | 121 | 41 | 3,435 | |||||||||||||||||||||||
Charged/(Credited) to Earnings |
(246 | ) | (167 | ) | (39 | ) | (24 | ) | (476 | ) | ||||||||||||||||||
Charged/(Credited) to OCI |
192 | - | - | - | 192 | |||||||||||||||||||||||
As at December 31, 2015 |
3,052 | - | 82 | 17 | 3,151 |
Cenovus Energy Inc. | 27 | Consolidated Financial Statements |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2015
Deferred Income Tax Assets | Unused Tax Losses |
Timing of Partnership Items |
Risk Management |
Other | Total | |||||||||||||||||||||
As at December 31, 2013 |
(104) | - | (35 | ) | (241 | ) | (380 | ) | ||||||||||||||||||
Charged/(Credited) to Earnings |
41 | - | 31 | 178 | 250 | |||||||||||||||||||||
Charged/(Credited) to OCI |
(9) | - | - | 6 | (3 | ) | ||||||||||||||||||||
As at December 31, 2014 |
(72) | - | (4 | ) | (57 | ) | (133 | ) | ||||||||||||||||||
Charged/(Credited) to Earnings |
(80) | (36 | ) | (4 | ) | (59 | ) | (179 | ) | |||||||||||||||||
Charged/(Credited) to OCI |
(20) | - | - | (3 | ) | (23 | ) | |||||||||||||||||||
As at December 31, 2015 |
(172) | (36 | ) | (8 | ) | (119 | ) | (335 | ) | |||||||||||||||||
Net Deferred Income Tax Liabilities | Total | |||||||||||||||||||||||||
Net Deferred Income Tax Liabilities as at December 31, 2013 |
2,862 | |||||||||||||||||||||||||
Charged/(Credited) to Earnings |
359 | |||||||||||||||||||||||||
Charged/(Credited) to OCI |
81 | |||||||||||||||||||||||||
Net Deferred Income Tax Liabilities as at December 31, 2014 |
3,302 | |||||||||||||||||||||||||
Charged/(Credited) to Earnings |
(655 | ) | ||||||||||||||||||||||||
Charged/(Credited) to OCI |
169 | |||||||||||||||||||||||||
Net Deferred Income Tax Liabilities as at December 31, 2015 |
2,816 |
No deferred tax liability has been recognized as at December 31, 2015 on temporary differences associated with investments in subsidiaries and joint arrangements where the Company can control the timing of the reversal of the temporary difference and the reversal is not probable in the foreseeable future. As at December 31, 2015, the Company had temporary differences of $6,692 million (2014 $6,667 million) in respect of certain of these investments where, on dissolution or sale, a tax liability may exist.
The approximate amounts of tax pools available are:
As at December 31, | 2015 | 2014 | ||||||||
Canada |
4,882 | 6,153 | ||||||||
United States |
2,119 | 958 | ||||||||
7,001 | 7,111 |
As at December 31, 2015, the above tax pools included $13 million (2014 $8 million) of Canadian non-capital losses and $380 million (2014 $140 million) of U.S. federal net operating losses. These losses expire no earlier than 2031.
Also included in the December 31, 2015 tax pools are Canadian net capital losses totaling $44 million (2014 $593 million), which are available for carry forward to reduce future capital gains. Of these losses, $41 million are unrecognized as a deferred income tax asset as at December 31, 2015 (2014 $559 million). Recognition is dependent on future capital gains. The Company has not recognized $828 million of net capital losses associated with unrealized foreign exchange losses on its U.S. denominated debt.
Cenovus Energy Inc. | 28 | Consolidated Financial Statements |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2015
A) Net Earnings Per Share
For the years ended December 31, | 2015 | 2014 | 2013 | |||||||||||||
Net Earnings Basic and Diluted ($ millions) |
618 | 744 | 662 | |||||||||||||
Basic Weighted Average Number of Shares (millions) |
818.7 | 756.9 | 755.9 | |||||||||||||
Dilutive Effect of Cenovus TSARs |
- | 0.7 | 1.6 | |||||||||||||
Dilutive Effect of Cenovus NSRs |
- | - | - | |||||||||||||
Diluted Weighted Average Number of Shares |
818.7 | 757.6 | 757.5 | |||||||||||||
Net Earnings Per Share ($) |
||||||||||||||||
Basic |
$0.75 | $0.98 | $0.88 | |||||||||||||
Diluted |
$0.75 | $0.98 | $0.87 |
B) Dividends Per Share
For the year ended December 31, 2015, the Company paid dividends of $710 million or $0.8524 per share (2014 $805 million, $1.0648 per share; 2013 $732 million, $0.968 per share), including cash dividends of $528 million. For 2014 and 2013, all dividends were paid in cash. The Cenovus Board of Directors declared a first quarter dividend of $0.05 per share, payable on March 31, 2016, to common shareholders of record as of March 15, 2016.
As at December 31, | 2015 | 2014 | ||||||||
Cash |
323 | 458 | ||||||||
Short-Term Investments |
3,782 | 425 | ||||||||
4,105 | 883 |
13. ACCOUNTS RECEIVABLE AND ACCRUED REVENUES
As at December 31, | 2015 | 2014 | ||||||||
Accruals |
1,037 | 1,417 | ||||||||
Partner Advances |
35 | 44 | ||||||||
Prepaids and Deposits |
71 | 56 | ||||||||
Trade |
61 | 6 | ||||||||
Joint Operations Receivables |
13 | 18 | ||||||||
Other |
34 | 41 | ||||||||
1,251 | 1,582 |
Cenovus Energy Inc. | 29 | Consolidated Financial Statements |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2015
As at December 31, | 2015 | 2014 | ||||||||
Product |
||||||||||
Refining and Marketing |
591 | 972 | ||||||||
Oil Sands |
158 | 182 | ||||||||
Conventional |
11 | 28 | ||||||||
Parts and Supplies |
50 | 42 | ||||||||
810 | 1,224 |
During the year ended December 31, 2015, approximately $10,618 million of produced and purchased inventory was recorded as an expense (2014 $15,065 million; 2013 $13,895 million).
As a result of a decline in commodity prices, Cenovus recorded a write-down of its product inventory of $66 million from cost to net realizable value as at December 31, 2015 (2014 $131 million).
15. EXPLORATION AND EVALUATION ASSETS
COST |
||||
As at December 31, 2013 |
1,473 | |||
Additions |
279 | |||
Transfers to PP&E (Note 16) |
(53 | ) | ||
Exploration Expense (Note 9) |
(86 | ) | ||
Divestitures |
(2 | ) | ||
Change in Decommissioning Liabilities |
14 | |||
As at December 31, 2014 |
1,625 | |||
Additions |
138 | |||
Acquisitions |
3 | |||
Transfers to PP&E (Note 16) |
(49 | ) | ||
Exploration Expense (Note 9) |
(138 | ) | ||
Change in Decommissioning Liabilities |
(4 | ) | ||
As at December 31, 2015 |
1,575 |
Cenovus Energy Inc. | 30 | Consolidated Financial Statements |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2015
16. PROPERTY, PLANT AND EQUIPMENT, NET
Upstream Assets | ||||||||||||||||||||||||||||
Development & Production |
Other Upstream |
Refining Equipment |
Other (1) | Total | ||||||||||||||||||||||||
COST |
||||||||||||||||||||||||||||
As at December 31, 2013 |
29,390 | 286 | 3,654 | 849 | 34,179 | |||||||||||||||||||||||
Additions |
2,522 | 43 | 162 | 63 | 2,790 | |||||||||||||||||||||||
Transfers From E&E Assets (Note 15) |
53 | - | - | - | 53 | |||||||||||||||||||||||
Transfers to Assets Held for Sale |
(55 | ) | - | - | - | (55 | ) | |||||||||||||||||||||
Change in Decommissioning Liabilities |
264 | - | (3 | ) | - | 261 | ||||||||||||||||||||||
Exchange Rate Movements and Other |
1 | - | 338 | - | 339 | |||||||||||||||||||||||
Divestitures |
(474 | ) | - | - | (2 | ) | (476 | ) | ||||||||||||||||||||
As at December 31, 2014 |
31,701 | 329 | 4,151 | 910 | 37,091 | |||||||||||||||||||||||
Additions |
1,289 | 2 | 240 | 45 | 1,576 | |||||||||||||||||||||||
Acquisition (Note 17) |
1 | - | - | 83 | 84 | |||||||||||||||||||||||
Transfers From E&E Assets (Note 15) |
49 | - | - | - | 49 | |||||||||||||||||||||||
Change in Decommissioning Liabilities |
(635 | ) | - | 1 | (1 | ) | (635 | ) | ||||||||||||||||||||
Exchange Rate Movements and Other |
(1 | ) | - | 814 | - | 813 | ||||||||||||||||||||||
Divestitures (Note 8) |
(923 | ) | - | - | - | (923 | ) | |||||||||||||||||||||
As at December 31, 2015 |
31,481 | 331 | 5,206 | 1,037 | 38,055 | |||||||||||||||||||||||
ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION |
||||||||||||||||||||||||||||
As at December 31, 2013 |
15,791 | 193 | 386 | 475 | 16,845 | |||||||||||||||||||||||
Depreciation, Depletion and Amortization |
1,602 | 40 | 156 | 83 | 1,881 | |||||||||||||||||||||||
Transfers to Assets Held for Sale |
(27 | ) | - | - | - | (27 | ) | |||||||||||||||||||||
Impairment Losses (Note 9) |
65 | - | - | - | 65 | |||||||||||||||||||||||
Exchange Rate Movements and Other |
38 | - | 42 | - | 80 | |||||||||||||||||||||||
Divestitures |
(316 | ) | - | - | - | (316 | ) | |||||||||||||||||||||
As at December 31, 2014 |
17,153 | 233 | 584 | 558 | 18,528 | |||||||||||||||||||||||
Depreciation, Depletion and Amortization |
1,601 | 44 | 189 | 80 | 1,914 | |||||||||||||||||||||||
Impairment Losses (Note 9) |
200 | - | - | - | 200 | |||||||||||||||||||||||
Exchange Rate Movements and Other |
(1 | ) | - | 123 | 1 | 123 | ||||||||||||||||||||||
Divestitures (Note 8) |
(45 | ) | - | - | - | (45 | ) | |||||||||||||||||||||
As at December 31, 2015 |
18,908 | 277 | 896 | 639 | 20,720 | |||||||||||||||||||||||
CARRYING VALUE |
||||||||||||||||||||||||||||
As at December 31, 2013 |
13,599 | 93 | 3,268 | 374 | 17,334 | |||||||||||||||||||||||
As at December 31, 2014 |
14,548 | 96 | 3,567 | 352 | 18,563 | |||||||||||||||||||||||
As at December 31, 2015 |
12,573 | 54 | 4,310 | 398 | 17,335 |
(1) Includes crude-by-rail terminal, office furniture, fixtures, leasehold improvements, information technology and aircraft.
PP&E includes the following amounts in respect of assets under construction and not subject to DD&A:
As at December 31, | 2015 | 2014 | ||||||||
Development and Production |
537 | 478 | ||||||||
Refining Equipment |
265 | 159 | ||||||||
802 | 637 |
Cenovus Energy Inc. | 31 | Consolidated Financial Statements |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2015
On August 31, 2015, the Company completed the acquisition of a crude-by-rail terminal for cash consideration of $75 million, plus adjustments. The transaction was accounted for using the acquisition method of accounting. In connection with the acquisition, the Company assumed an associated decommissioning liability of $4 million, working capital of $1 million and net transportation commitments of $92 million. Transaction costs associated with the acquisition have been expensed. These assets and results of operations are reported in the Refining and Marketing segment.
As at December 31, | 2015 | 2014 | ||||||||
Investments |
46 | 36 | ||||||||
Long-Term Receivables |
1 | 7 | ||||||||
Prepaids |
7 | 7 | ||||||||
Other |
22 | 20 | ||||||||
76 | 70 |
As at December 31, | 2015 | 2014 | ||||||||
Carrying Value, Beginning of Year |
242 | 739 | ||||||||
Impairment Losses (Note 9) |
- | (497 | ) | |||||||
Carrying Value, End of Year |
242 | 242 |
All of the Companys goodwill arose in 2002 upon the formation of the predecessor corporation. As at December 31, 2015 and 2014, the carrying amount of goodwill was associated with the Companys Primrose (Foster Creek) CGU.
20. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
As at December 31, | 2015 | 2014 | ||||||||
Accruals |
1,366 | 2,057 | ||||||||
Partner Advances |
35 | 218 | ||||||||
Trade |
68 | 51 | ||||||||
Employee Long-Term Incentives |
47 | 91 | ||||||||
Interest |
73 | 61 | ||||||||
Other |
113 | 110 | ||||||||
1,702 | 2,588 |
As at December 31, | 2015 | 2014 | ||||||||||
Revolving Term Debt (1) |
A | - | - | |||||||||
U.S. Dollar Denominated Unsecured Notes |
B | 6,574 | 5,510 | |||||||||
Total Debt Principal |
C | 6,574 | 5,510 | |||||||||
Debt Discounts and Transaction Costs |
D | (49 | ) | (52 | ) | |||||||
6,525 | 5,458 |
(1) Revolving term debt may include bankers acceptances, LIBOR loans, prime rate loans and U.S. base rate loans.
Cenovus Energy Inc. | 32 | Consolidated Financial Statements |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2015
The weighted average interest rate on outstanding debt for the year ended December 31, 2015 was 5.3 percent (2014 5.0 percent).
A) Revolving Term Debt
As at December 31, 2015, Cenovus had in place a committed credit facility in the amount of $4.0 billion or the equivalent amount in U.S. dollars. During the second quarter of 2015, Cenovus renegotiated its existing $3.0 billion committed credit facility, extending the maturity date to November 30, 2019. In addition, a new $1.0 billion tranche was established under the same facility, maturing on November 30, 2017. The maturity dates are extendable from time to time, at the option of Cenovus and upon agreement from the lenders. Borrowings are available by way of Bankers Acceptances, LIBOR based loans, prime rate loans or U.S. base rate loans. As at December 31, 2015, there were no amounts drawn on Cenovuss committed bank credit facility (December 31, 2014 $nil).
B) Unsecured Notes
Unsecured notes are composed of:
As at December 31, | US$ Principal Amount |
2015 | 2014 | |||||||||||||
5.70% due October 15, 2019 |
1,300 | 1,799 | 1,508 | |||||||||||||
3.00% due August 15, 2022 |
500 | 692 | 580 | |||||||||||||
3.80% due September 15, 2023 |
450 | 623 | 522 | |||||||||||||
6.75% due November 15, 2039 |
1,400 | 1,938 | 1,624 | |||||||||||||
4.45% due September 15, 2042 |
750 | 1,038 | 870 | |||||||||||||
5.20% due September 15, 2043 |
350 | 484 | 406 | |||||||||||||
6,574 | 5,510 |
On June 24, 2014, Cenovus filed a U.S. base shelf prospectus for unsecured notes in the amount of US$2.0 billion. The U.S. base shelf prospectus allows for the issuance of debt securities in U.S. dollars or other currencies from time to time in one or more offerings. Terms of the notes, including, but not limited to, interest at either fixed or floating rates and maturity dates will be determined at the date of issue. As at December 31, 2015, no notes have been issued under this U.S. base shelf prospectus. The U.S. base shelf prospectus expires in July 2016.
On June 25, 2014, Cenovus filed a Canadian base shelf prospectus for unsecured medium term notes in the amount of $1.5 billion. The Canadian base shelf prospectus allows for the issuance of medium term notes in Canadian dollars or other currencies from time to time in one or more offerings. Terms of the notes, including, but not limited to, interest at either fixed or floating rates and maturity dates will be determined at the date of issue. As at December 31, 2015, no medium term notes have been issued under this Canadian base shelf prospectus. The Canadian base shelf prospectus expires in July 2016.
As at December 31, 2015, the Company is in compliance with all of the terms of its debt agreements.
C) Mandatory Debt Payments
US$ Principal Amount |
C$ Principal Amount |
Total C$ Equivalent |
||||||||||||||
2016 |
- | - | - | |||||||||||||
2017 |
- | - | - | |||||||||||||
2018 |
- | - | - | |||||||||||||
2019 |
1,300 | - | 1,799 | |||||||||||||
2020 |
- | - | - | |||||||||||||
Thereafter |
3,450 | - | 4,775 | |||||||||||||
4,750 | - | 6,574 |
D) Debt Discounts and Transaction Costs
Long-term debt transaction costs and discounts associated with the unsecured notes are recorded within long-term debt and are amortized using the effective interest rate method. Transaction costs associated with the revolving term debt are recorded as a prepayment and are amortized over the remaining term of the committed credit facility. During 2015, additional transaction costs of $3 million were recorded (2014 $2 million).
Cenovus Energy Inc. | 33 | Consolidated Financial Statements |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2015
22. DECOMMISSIONING LIABILITIES
The decommissioning provision represents the present value of the expected future costs associated with the retirement of upstream crude oil and natural gas assets, refining facilities and the crude-by-rail terminal. The aggregate carrying amount of the obligation is:
As at December 31, | 2015 | 2014 | ||||||||
Decommissioning Liabilities, Beginning of Year |
2,616 | 2,370 | ||||||||
Liabilities Incurred |
10 | 48 | ||||||||
Liabilities Acquired |
4 | - | ||||||||
Liabilities Settled |
(62 | ) | (93 | ) | ||||||
Liabilities Divested |
- | (60 | ) | |||||||
Transfers and Reclassifications |
- | (9 | ) | |||||||
Change in Estimated Future Cash Flows |
(70 | ) | 115 | |||||||
Change in Discount Rate |
(579 | ) | 122 | |||||||
Unwinding of Discount on Decommissioning Liabilities |
126 | 120 | ||||||||
Foreign Currency Translation |
7 | 3 | ||||||||
Decommissioning Liabilities, End of Year |
2,052 | 2,616 |
The undiscounted amount of estimated future cash flows required to settle the obligation is $6,665 million (December 31, 2014 $8,333 million), which has been discounted using a credit-adjusted risk-free rate of 6.4 percent (December 31, 2014 4.9 percent). An inflation rate of two percent (2014 two percent) was used to calculate the decommissioning provision. Most of these obligations are not expected to be paid for several years, or decades, and are expected to be funded from general resources at that time. The Company expects to settle approximately $35 million to $70 million of decommissioning liabilities over the next year. Revisions in estimated future cash flows resulted from lower cost estimates, partially offset by accelerated timing of decommissioning liabilities over the estimated life of the reserves.
Sensitivities
Changes to the credit-adjusted risk-free rate or the inflation rate would have the following impact on the decommissioning liabilities:
2015 | 2014 | |||||||||||||||||||||
As at December 31, |
Credit-Adjusted Risk-Free Rate |
Inflation Rate | Credit-Adjusted Risk-Free Rate |
Inflation Rate | ||||||||||||||||||
One Percent Increase |
(247) | 319 | (419 | ) | 574 | |||||||||||||||||
One Percent Decrease |
308 | (259) | 562 | (433 | ) |
As at December 31, | 2015 | 2014 | ||||||||
Employee Long-Term Incentives |
40 | 57 | ||||||||
Pension and OPEB (Note 24) |
66 | 84 | ||||||||
Other |
36 | 31 | ||||||||
142 | 172 |
Cenovus Energy Inc. | 34 | Consolidated Financial Statements |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2015
24. PENSIONS AND OTHER POST-EMPLOYMENT BENEFITS
The Company provides employees with a pension that includes either a defined contribution or defined benefit component and OPEB. Most of the employees participate in the defined contribution pension. Starting in 2012, employees who meet certain criteria may move from the current defined contribution component to a defined benefit component for their future service.
The defined benefit pension provides pension benefits at retirement based on years of service and final average earnings. Future enrollment is limited to eligible employees who meet certain criteria. The Companys OPEB provides certain retired employees with health care and dental benefits until age 65 and life insurance benefits.
The Company is required to file an actuarial valuation of its registered defined benefit pension with the provincial regulator at least every three years. The most recently filed valuation was dated December 31, 2014 and the next required actuarial valuation will be as at December 31, 2017.
A) Defined Benefit and OPEB Plan Obligation and Funded Status
Information related to defined benefit pension and OPEB plans, based on actuarial estimations, is:
Pension Benefits | OPEB | |||||||||||||||||||||
As at December 31, | 2015 | 2014 | 2015 | 2014 | ||||||||||||||||||
Defined Benefit Obligation |
||||||||||||||||||||||
Defined Benefit Obligation, Beginning of Year |
200 | 148 | 23 | 18 | ||||||||||||||||||
Current Service Costs |
19 | 15 | 3 | 2 | ||||||||||||||||||
Interest Costs (1) |
8 | 7 | 1 | 1 | ||||||||||||||||||
Benefits Paid |
(6 | ) | (3 | ) | (1 | ) | - | |||||||||||||||
Plan Participant Contributions |
3 | 3 | - | - | ||||||||||||||||||
Past Service Costs Curtailments |
(5 | ) | - | - | - | |||||||||||||||||
Settlements |
(20 | ) | - | - | - | |||||||||||||||||
Remeasurements: |
||||||||||||||||||||||
(Gains) Losses from Experience Adjustments |
(3 | ) | - | - | - | |||||||||||||||||
(Gains) Losses from Changes in Demographic Assumptions |
- | (1 | ) | - | - | |||||||||||||||||
(Gains) Losses from Changes in Financial Assumptions |
(28 | ) | 31 | - | 2 | |||||||||||||||||
Defined Benefit Obligation, End of Year |
168 | 200 | 26 | 23 | ||||||||||||||||||
Plan Assets |
||||||||||||||||||||||
Fair Value of Plan Assets, Beginning of Year |
139 | 115 | - | - | ||||||||||||||||||
Employer Contributions |
16 | 12 | - | - | ||||||||||||||||||
Plan Participant Contributions |
3 | 3 | - | - | ||||||||||||||||||
Benefits Paid |
(6 | ) | (3 | ) | - | - | ||||||||||||||||
Settlements |
(23 | ) | - | - | - | |||||||||||||||||
Interest Income (1) |
2 | 4 | - | - | ||||||||||||||||||
Remeasurements: |
||||||||||||||||||||||
Return on Plan Assets (Excluding Interest Income) |
(3 | ) | 8 | - | - | |||||||||||||||||
Fair Value of Plan Assets, End of Year |
128 | 139 | - | - | ||||||||||||||||||
Pension and Other Post-Employment Benefit (Liability) (2) |
(40 | ) | (61 | ) | (26 | ) | (23 | ) |
(1) Based on the discount rate of the defined benefit obligation at the beginning of the year.
(2) Pension and OPEB liabilities are included in other liabilities on the Consolidated Balance Sheets.
The weighted average duration of the defined benefit pension and OPEB obligations are 15 years and 12 years, respectively.
Cenovus Energy Inc. | 35 | Consolidated Financial Statements |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2015
B) Pension and OPEB Costs
Pension Benefits | OPEB | |||||||||||||||||||||||||||||||||
For the years ended December 31, | 2015 | 2014 | 2013 | 2015 | 2014 | 2013 | ||||||||||||||||||||||||||||
Defined Benefit Plan Cost |
||||||||||||||||||||||||||||||||||
Current Service Costs |
19 | 15 | 17 | 3 | 2 | 2 | ||||||||||||||||||||||||||||
Past Service Costs Curtailments |
(5 | ) | - | - | - | - | - | |||||||||||||||||||||||||||
Net Settlement Costs |
3 | - | - | - | - | - | ||||||||||||||||||||||||||||
Net Interest Costs |
6 | 3 | 4 | 1 | 1 | 1 | ||||||||||||||||||||||||||||
Remeasurements: |
||||||||||||||||||||||||||||||||||
Return on Plan Assets (Excluding Interest Income) |
3 | (8 | ) | (7 | ) | - | - | - | ||||||||||||||||||||||||||
(Gains) Losses from Experience Adjustments |
(3 | ) | - | 1 | - | - | - | |||||||||||||||||||||||||||
(Gains) Losses from Changes in Demographic Assumptions |
- | (1 | ) | 12 | - | - | (1 | ) | ||||||||||||||||||||||||||
(Gains) Losses from Changes in Financial Assumptions |
(28 | ) | 31 | (19 | ) | - | 2 | (4 | ) | |||||||||||||||||||||||||
Defined Benefit Plan Cost (Gain) |
(5 | ) | 40 | 8 | 4 | 5 | (2 | ) | ||||||||||||||||||||||||||
Defined Contribution Plan Cost |
29 | 30 | 27 | - | - | - | ||||||||||||||||||||||||||||
Total Plan Cost |
24 | 70 | 35 | 4 | 5 | (2 | ) |
C) Investment Objectives and Fair Value of Plan Assets
The objective of the asset allocation is to manage the funded status of the plan at an appropriate level of risk, giving consideration to the security of the assets and the potential volatility of market returns and the resulting effect on both contribution requirements and pension expense. The long-term return is expected to achieve or exceed the return from a composite benchmark comprised of passive investments in appropriate market indices. The asset allocation structure is subject to diversification requirements and constraints which reduce risk by limiting exposure to individual equity investment and credit rating categories.
The allocation of assets between the various types of investment funds is monitored monthly and is re-balanced as necessary. The asset allocation structure targets an investment of 60 to 70 percent in equity securities, 30 percent in debt instruments and the remainder invested in real estate and other.
The Company does not use derivative instruments to manage the risks of its plan assets. There has been no change in the process used by the Company to manage these risks from prior periods.
The fair value of the plan assets is:
As at December 31, | 2015 | 2014 | ||||||||
Equity Securities |
||||||||||
Equity Funds and Balanced Funds |
73 | 75 | ||||||||
Other |
3 | 9 | ||||||||
Bond Funds |
31 | 36 | ||||||||
Non-Invested Assets |
17 | 15 | ||||||||
Real Estate |
4 | 4 | ||||||||
128 | 139 |
Fair value of equity securities and bond funds are based on the trading price of the underlying funds. The fair value of the non-invested assets is the discounted value of the expected future payments. The fair value of real estate is determined by accredited real estate appraisers.
Equity securities do not include any direct investments in Cenovus shares.
Cenovus Energy Inc. | 36 | Consolidated Financial Statements |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2015
D) Funding
The defined benefit pension is funded in accordance with federal and provincial government pension legislation, where applicable. Contributions are made to trust funds administered by an independent trustee. The Companys contributions to the defined benefit pension plan are based on the most recent actuarial valuation as at December 31, 2014, and direction by the Management Pension Committee and Human Resources and Compensation Committee of the Board of Directors.
Employees participating in the defined benefit pension are required to contribute four percent of their pensionable earnings, up to an annual maximum, and the Company provides the balance of the funding necessary to ensure benefits will be fully provided for at retirement. The expected employer contributions for the year ended December 31, 2016 are $15 million for the defined benefit pension plan and $nil for the OPEB. The OPEB is funded on an as required basis.
E) Actuarial Assumptions and Sensitivities
Actuarial Assumptions
The principal weighted average actuarial assumptions used to determine benefit obligations and expenses are as follows:
Pension Benefits | OPEB | |||||||||||||||||||||||||||||||||
For the years ended December 31, | 2015 | 2014 | 2013 | 2015 | 2014 | 2013 | ||||||||||||||||||||||||||||
Discount Rate |
4.00% | 3.75% | 4.75% | 3.75% | 3.75% | 4.75% | ||||||||||||||||||||||||||||
Future Salary Growth Rate |
3.80% | 4.32% | 4.39% | 5.15% | 5.65% | 5.65% | ||||||||||||||||||||||||||||
Average Longevity (Years) |
88.3 | 88.3 | 88.5 | 88.3 | 88.3 | 88.5 | ||||||||||||||||||||||||||||
Health Care Cost Trend Rate |
N/A | N/A | N/A | 7.00% | 7.00% | 7.00% |
The discount rates are determined with reference to market yields on high quality corporate debt instruments of similar duration to the benefit obligations at the end of the reporting period.
Sensitivities
The sensitivity of the defined benefit and OPEB obligation to changes in relevant actuarial assumptions is shown below.
2015 | 2014 | |||||||||||||||||||||
As at December 31, | One Percentage Point Increase |
One Percentage Point Decrease |
One Percentage Point Increase |
One Percentage Point Decrease |
||||||||||||||||||
Discount Rate |
(27 | ) | 35 | (34 | ) | 43 | ||||||||||||||||
Future Salary Growth Rate |
3 | (3 | ) | 4 | (4 | ) | ||||||||||||||||
Health Care Cost Trend Rate |
2 | (2 | ) | 2 | (2 | ) | ||||||||||||||||
Future Mortality Rate (Years) |
4 | (4 | ) | 4 | (4 | ) |
The above sensitivity analysis is based on a change in an assumption while holding all other assumptions constant; however, the changes in some assumptions may be correlated. The same methodologies have been used to calculate the sensitivity of the defined benefit obligation to significant actuarial assumptions as have been applied when calculating the defined benefit pension liability recorded on the Consolidated Balance Sheets.
F) Risks
Through its defined benefit pension and OPEB plans, the Company is exposed to actuarial risks, such as longevity risk, interest rate risk, investment risk and salary risk.
Longevity Risk
The present value of the defined benefit plan obligation is calculated by reference to the best estimate of the mortality of plan participants both during and after their employment. An increase in the life expectancy of participants will increase the defined benefit plan obligation.
Cenovus Energy Inc. | 37 | Consolidated Financial Statements |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2015
Interest Rate Risk
A decrease in corporate bond yields will increase the defined benefit plan obligation, although this will be partially offset by an increase in the return on debt holdings.
Investment Risk
The present value of the defined benefit plan obligation is calculated using a discount rate determined by reference to high quality corporate bond yields. If the return on plan assets is below this rate, a plan deficit will result. Due to the long-term nature of the plan liabilities, a higher portion of the plan assets are invested in equity securities than in debt instruments and real estate.
Salary Risk
The present value of the defined benefit plan obligation is calculated by reference to the future salaries of plan participants. As such, an increase in the salary of the plan participants will increase the defined benefit obligation.
A) Authorized
Cenovus is authorized to issue an unlimited number of common shares and first and second preferred shares not exceeding, in aggregate, 20 percent of the number of issued and outstanding common shares. The first and second preferred shares may be issued in one or more series with rights and conditions to be determined by the Companys Board of Directors prior to issuance and subject to the Companys articles.
B) Issued and Outstanding
2015 | 2014 | |||||||||||||||||||||
As at December 31, | Number of (Thousands) |
Amount | Number of (Thousands) |
Amount | ||||||||||||||||||
Outstanding, Beginning of Year |
757,103 | 3,889 | 756,046 | 3,857 | ||||||||||||||||||
Common Shares Issued, Net of Issuance Costs |
67,500 | 1,463 | - | - | ||||||||||||||||||
Common Shares Issued Pursuant to Dividend Reinvestment Plan |
8,687 | 182 | - | - | ||||||||||||||||||
Common Shares Issued Under Stock Option Plans |
- | - | 1,057 | 32 | ||||||||||||||||||
Outstanding, End of Year |
833,290 | 5,534 | 757,103 | 3,889 |
On March 3, 2015, Cenovus issued 67.5 million common shares at a price of $22.25 per common share. Share issuance costs of $53 million were incurred.
The Company has a DRIP, whereby holders of common shares may reinvest all or a portion of the cash dividends payable on their common shares in additional common shares. At the discretion of the Company, the additional common shares may be issued from treasury of the Company or purchased on the market. During the year ended December 31, 2015, the Company issued 8.7 million common shares from treasury under the DRIP.
There were no preferred shares outstanding as at December 31, 2015 (2014 nil).
As at December 31, 2015, there were 12 million (2014 13 million) common shares available for future issuance under the stock option plan.
Cenovus Energy Inc. | 38 | Consolidated Financial Statements |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2015
C) Paid in Surplus
Cenovuss paid in surplus reflects the Companys retained earnings prior to the split of Encana Corporation (Encana) under the plan of arrangement into two independent energy companies, Encana and Cenovus. In addition, paid in surplus includes stock-based compensation expense related to the Companys NSRs discussed in Note 27A).
Pre-Arrangement Earnings |
Stock-Based Compensation |
Total | ||||||||||||||
As at December 31, 2013 |
4,086 | 133 | 4,219 | |||||||||||||
Stock-Based Compensation Expense |
- | 72 | 72 | |||||||||||||
As at December 31, 2014 |
4,086 | 205 | 4,291 | |||||||||||||
Stock-Based Compensation Expense |
- | 39 | 39 | |||||||||||||
As at December 31, 2015 |
4,086 | 244 | 4,330 |
26. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
Defined Benefit Plan |
Foreign Currency Translation |
Available for Sale |
Total | |||||||||||||||||||
As at December 31, 2013 |
(12 | ) | 212 | 10 | 210 | |||||||||||||||||
Other Comprehensive Income (Loss), Before Tax |
(24 | ) | 215 | - | 191 | |||||||||||||||||
Income Tax |
6 | - | - | 6 | ||||||||||||||||||
As at December 31, 2014 |
(30 | ) | 427 | 10 | 407 | |||||||||||||||||
Other Comprehensive Income (Loss), Before Tax |
28 | 587 | 8 | 623 | ||||||||||||||||||
Income Tax |
(8 | ) | - | (2 | ) | (10 | ) | |||||||||||||||
As at December 31, 2015 |
(10 | ) | 1,014 | 16 | 1,020 |
27. STOCK-BASED COMPENSATION PLANS
A) Employee Stock Option Plan
Cenovus has an Employee Stock Option Plan that provides employees with the opportunity to exercise an option to purchase a common share of the Company. Option exercise prices approximate the market price for the common shares on the date the options were issued. Options granted are exercisable at 30 percent of the number granted after one year, an additional 30 percent of the number granted after two years and are fully exercisable after three years. Options expire after seven years.
Options issued by the Company under the Employee Stock Option Plan prior to February 24, 2011 have associated tandem stock appreciation rights. In lieu of exercising the options, the tandem stock appreciation rights give the option holder the right to receive a cash payment equal to the excess of the market price of Cenovuss common shares at the time of exercise over the exercise price of the option.
Options issued by the Company on or after February 24, 2011 have associated net settlement rights. The net settlement rights, in lieu of exercising the option, give the option holder the right to receive the number of common shares that could be acquired with the excess value of the market price of Cenovuss common shares at the time of exercise over the exercise price of the option.
The tandem stock appreciation rights and net settlement rights vest and expire under the same terms and conditions as the underlying options. For the purpose of this financial statement note, options with associated tandem stock appreciation rights are referred to as TSARs and options with associated net settlement rights are referred to as NSRs.
In addition, certain of the TSARs are performance based (performance TSARs). All performance TSARs have vested, and, as such, terms and conditions are consistent with TSARs, which were not performance based.
Cenovus Energy Inc. | 39 | Consolidated Financial Statements |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2015
NSRs
The weighted average unit fair value of NSRs granted during the year ended December 31, 2015 was $3.58 before considering forfeitures, which are considered in determining total cost for the period. The fair value of each NSR was estimated on its grant date using the Black-Scholes-Merton valuation model with weighted average assumptions as follows:
Risk-Free Interest Rate |
0.75% | |||
Expected Dividend Yield |
3.60% | |||
Expected Volatility (1) |
28.27% | |||
Expected Life (Years) |
4.55 |
(1) Expected volatility has been based on historical share volatility of the Company and comparable industry peers.
The following tables summarize information related to the NSRs:
As at December 31, 2015 |
Number of (Thousands) |
Weighted Average Exercise Price ($) |
||||||||
Outstanding, Beginning of Year |
40,549 | 32.63 | ||||||||
Granted |
4,106 | 22.25 | ||||||||
Exercised |
- | - | ||||||||
Forfeited |
(2,541 | ) | 32.19 | |||||||
Outstanding, End of Year |
42,114 | 31.65 | ||||||||
Exercisable, End of Year |
23,484 | 34.46 |
Outstanding NSRs | ||||||||||||||||
As at December 31, 2015 Range of Exercise Price ($) |
Number of NSRs (Thousands) |
Weighted Average Remaining Contractual Life (Years) |
Weighted Average Exercise Price ($) |
|||||||||||||
15.00 to 19.99 |
6 | 6.68 | 18.07 | |||||||||||||
20.00 to 24.99 |
4,075 | 6.15 | 22.26 | |||||||||||||
25.00 to 29.99 |
14,281 | 5.14 | 28.39 | |||||||||||||
30.00 to 34.99 |
12,642 | 4.18 | 32.61 | |||||||||||||
35.00 to 39.99 |
11,110 | 2.79 | 38.19 | |||||||||||||
42,114 | 4.33 | 31.65 |
Exercisable NSRs | ||||||||||
As at December 31, 2015 Range of Exercise Price ($) |
Number of NSRs (Thousands) |
Weighted Average Exercise Price ($) |
||||||||
15.00 to 19.99 |
- | - | ||||||||
20.00 to 24.99 |
40 | 22.99 | ||||||||
25.00 to 29.99 |
4,404 | 28.41 | ||||||||
30.00 to 34.99 |
7,930 | 32.64 | ||||||||
35.00 to 39.99 |
11,110 | 38.19 | ||||||||
23,484 | 34.46 |
Cenovus Energy Inc. | 40 | Consolidated Financial Statements |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2015
TSARs
The Company has recorded a liability of $1 million as at December 31, 2015 (December 31, 2014 $8 million) in the Consolidated Balance Sheets based on the fair value of each TSAR held by Cenovus employees. Fair value was estimated at the period-end date using the Black-Scholes-Merton valuation model with weighted average assumptions as follows:
Risk-Free Interest Rate |
|
0.75% |
| |
Expected Dividend Yield |
4.14% | |||
Expected Volatility (1) |
29.24% | |||
Cenovuss Common Share Price |
$17.50 |
(1) Expected volatility has been based on historical share volatility of the Company and comparable industry peers.
The intrinsic value of vested TSARs held by Cenovus employees as at December 31, 2015 was $nil (December 31, 2014 $nil).
The following tables summarize information related to the TSARs held by Cenovus employees:
As at December 31, 2015 | Number of (Thousands) |
Weighted Average Exercise Price ($) |
||||||||||||||
Outstanding, Beginning of Year |
3,862 | 26.72 | ||||||||||||||
Exercised for Cash Payment |
- | - | ||||||||||||||
Exercised as Options for Common Shares |
- | - | ||||||||||||||
Forfeited |
(144 | ) | 27.06 | |||||||||||||
Expired |
(73 | ) | 25.89 | |||||||||||||
Outstanding, End of Year |
3,645 | 26.72 | ||||||||||||||
Exercisable, End of Year |
3,645 | 26.72 | ||||||||||||||
Outstanding and Exercisable TSARs | ||||||||||||||||
As at December 31, 2015 Range of Exercise Price ($) |
Number of TSARs (Thousands) |
Weighted Average Remaining Contractual Life (Years) |
Weighted Average Exercise Price ($) |
|||||||||||||
20.00 to 29.99 |
3,497 | 1.16 | 26.46 | |||||||||||||
30.00 to 39.99 |
148 | 1.98 | 32.88 | |||||||||||||
3,645 | 1.20 | 26.72 |
The closing price of Cenovuss common shares on the TSX as at December 31, 2015 was $17.50.
B) Performance Share Units
Cenovus has granted PSUs to certain employees under its Performance Share Unit Plan for Employees. PSUs are whole share units and entitle employees to receive, upon vesting, either a common share of Cenovus or a cash payment equal to the value of a Cenovus common share. For a portion of PSUs, the number of PSUs eligible for payment is determined over three years based on the units granted multiplied by 30 percent after year one, 30 percent after year two and 40 percent after year three. All PSUs are eligible to vest based on the Company achieving key pre-determined performance measures. PSUs vest after three years.
The Company has recorded a liability of $49 million as at December 31, 2015 (2014 $109 million) in the Consolidated Balance Sheets for PSUs based on the market value of Cenovuss common shares as at December 31, 2015. As PSUs are paid out upon vesting, the intrinsic value of vested PSUs was $nil as at December 31, 2015 and 2014.
Cenovus Energy Inc. | 41 | Consolidated Financial Statements |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2015
The following table summarizes the information related to the PSUs held by Cenovus employees:
As at December 31, 2015 | Number of PSUs (Thousands) |
|||
Outstanding, Beginning of Year |
7,099 | |||
Granted |
2,909 | |||
Vested and Paid Out |
(2,176 | ) | ||
Cancelled |
(1,681 | ) | ||
Units in Lieu of Dividends |
276 | |||
Outstanding, End of Year |
6,427 |
C) Restricted Share Units
Cenovus has granted RSUs to certain employees under its Restricted Share Unit Plan for Employees. RSUs are whole-share units and entitle employees to receive, upon vesting, either a common share of Cenovus or a cash payment equal to the value of a Cenovus common share. RSUs vest after three years.
RSUs are accounted for as liability instruments and are measured at fair value based on the market value of Cenovuss common shares at each period end. The fair value is recognized as stock-based compensation costs over the vesting period. Fluctuations in the fair value are recognized as stock-based compensation costs in the period they occur.
The Company has recorded a liability of $11 million as at December 31, 2015 (2014 $1 million) in the Consolidated Balance Sheets for RSUs based on the market value of Cenovuss common shares as at December 31, 2015. As RSUs are paid out upon vesting, the intrinsic value of vested RSUs was $nil as at December 31, 2015 and 2014.
The following table summarizes the information related to the RSUs held by Cenovus employees:
As at December 31, 2015 | Number of (Thousands) |
|||
Outstanding, Beginning of Year |
93 | |||
Granted |
2,345 | |||
Vested and Paid Out |
(22 | ) | ||
Cancelled |
(251 | ) | ||
Units in Lieu of Dividends |
102 | |||
Outstanding, End of Year |
2,267 |
D) Deferred Share Units
Under two Deferred Share Unit Plans, Cenovus directors, officers and employees may receive DSUs, which are equivalent in value to a common share of the Company. Employees have the option to convert either zero, 25 or 50 percent of their annual bonus award into DSUs. DSUs vest immediately, are redeemed in accordance with the terms of the agreement and expire on December 15 of the calendar year following the year of cessation of directorship or employment.
The Company has recorded a liability of $26 million as at December 31, 2015 (2014 $31 million) in the Consolidated Balance Sheets for DSUs based on the market value of Cenovuss common shares as at December 31, 2015. The intrinsic value of vested DSUs equals the carrying value as DSUs vest at the time of grant.
Cenovus Energy Inc. | 42 | Consolidated Financial Statements |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2015
The following table summarizes the information related to the DSUs held by Cenovus directors, officers and employees:
As at December 31, 2015 | Number of (Thousands) |
|||
Outstanding, Beginning of Year |
1,297 | |||
Granted to Directors |
68 | |||
Granted |
68 | |||
Units in Lieu of Dividends |
60 | |||
Redeemed |
(5 | ) | ||
Outstanding, End of Year |
1,488 |
E) Total Stock-Based Compensation
For the years ended December 31, | 2015 | 2014 | 2013 | |||||||||||||
NSRs |
27 | 41 | 35 | |||||||||||||
TSARs |
(5 | ) | (10 | ) | (16 | ) | ||||||||||
PSUs |
(13 | ) | 34 | 32 | ||||||||||||
RSUs |
6 | - | - | |||||||||||||
DSUs |
(5 | ) | (5 | ) | - | |||||||||||
Stock-Based Compensation Expense (Recovery) |
10 | 60 | 51 | |||||||||||||
Stock-Based Compensation Costs Capitalized |
6 | 29 | 18 | |||||||||||||
Total Stock-Based Compensation |
16 | 89 | 69 |
28. EMPLOYEE SALARIES AND BENEFIT EXPENSES
For the years ended December 31, | 2015 | 2014 | 2013 | |||||||||||||
Salaries, Bonuses and Other Short-Term Employee Benefits |
534 | 550 | 494 | |||||||||||||
Defined Contribution Pension Plan |
19 | 18 | 17 | |||||||||||||
Defined Benefit Pension Plan and OPEB |
17 | 14 | 15 | |||||||||||||
Stock-Based Compensation Expense (Note 27) |
10 | 60 | 51 | |||||||||||||
Termination Benefits |
43 | - | - | |||||||||||||
623 | 642 | 577 |
29. RELATED PARTY TRANSACTIONS
Key Management Compensation
Key management includes Directors (executive and non-executive), Executive Officers, Senior Vice-Presidents and Vice-Presidents. The compensation paid or payable to key management is:
For the years ended December 31, | 2015 | 2014 | 2013 | |||||||||||||
Salaries, Director Fees and Short-Term Benefits |
30 | 29 | 31 | |||||||||||||
Post-Employment Benefits |
5 | 4 | 4 | |||||||||||||
Stock-Based Compensation |
5 | 20 | 24 | |||||||||||||
40 | 53 | 59 |
Post-employment benefits represent the present value of future pension benefits earned during the year. Stock-based compensation includes the costs recorded during the year associated with stock options, NSRs, TSARs, PSUs, RSUs and DSUs.
Cenovus Energy Inc. | 43 | Consolidated Financial Statements |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2015
Cenovuss capital structure objectives and targets have remained unchanged from previous periods. Cenovuss capital structure consists of Shareholders Equity plus Debt. Debt is defined as short-term borrowings and the current and long-term portions of long-term debt. Net debt includes the Companys short-term borrowings, current and long-term portions of long-term debt, and the current and long-term portions of the Partnership Contribution Payable, net of cash and cash equivalents. Cenovuss objectives when managing its capital structure are to maintain financial flexibility, preserve access to capital markets, ensure its ability to finance internally generated growth and to fund potential acquisitions while maintaining the ability to meet the Companys financial obligations as they come due.
Cenovus monitors its capital structure and financing requirements using, among other things, non-GAAP financial metrics consisting of Debt to Capitalization and Debt to Adjusted Earnings Before Interest, Taxes and DD&A (Adjusted EBITDA). These metrics are used to steward Cenovuss overall debt position as measures of Cenovuss overall financial strength.
Over the long term, Cenovus targets a Debt to Capitalization ratio of between 30 and 40 percent and a Debt to Adjusted EBITDA ratio of between 1.0 and 2.0 times. At different points within the economic cycle, Cenovus expects these ratios may periodically be outside of the target range.
A) Debt to Capitalization and Net Debt to Capitalization
As at December 31, | 2015 | 2014 | 2013 | |||||||||||||||
Debt |
6,525 | 5,458 | 4,997 | |||||||||||||||
Add (Deduct): |
||||||||||||||||||
Cash and Cash Equivalents |
(4,105 | ) | (883 | ) | (2,452) | |||||||||||||
Current Portion of Partnership Contribution Payable (1) |
- | - | 438 | |||||||||||||||
Partnership Contribution Payable (1) |
- | - | 1,087 | |||||||||||||||
Net Debt |
2,420 | 4,575 | 4,070 | |||||||||||||||
Debt |
6,525 | 5,458 | 4,997 | |||||||||||||||
Shareholders Equity |
12,391 | 10,186 | 9,946 | |||||||||||||||
18,916 | 15,644 | 14,943 | ||||||||||||||||
Debt to Capitalization |
34% | 35% | 33% | |||||||||||||||
Net Debt |
2,420 | 4,575 | 4,070 | |||||||||||||||
Shareholders Equity |
12,391 | 10,186 | 9,946 | |||||||||||||||
14,811 | 14,761 | 14,016 | ||||||||||||||||
Net Debt to Capitalization |
16% | 31% | 29% |
(1) | In 2014, Cenovus repaid the remaining principal and accrued interest due under the Partnership Contribution Payable. |
Cenovus Energy Inc. | 44 | Consolidated Financial Statements |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2015
B) Debt to Adjusted EBITDA and Net Debt to Adjusted EBITDA
As at December 31, | 2015 | 2014 | 2013 | |||||||||||||||
Debt |
6,525 | 5,458 | 4,997 | |||||||||||||||
Net Debt |
2,420 | 4,575 | 4,070 | |||||||||||||||
Net Earnings |
618 | 744 | 662 | |||||||||||||||
Add (Deduct): |
||||||||||||||||||
Finance Costs |
482 | 445 | 529 | |||||||||||||||
Interest Income |
(28 | ) | (33 | ) | (96 | ) | ||||||||||||
Income Tax Expense (Recovery) |
(81 | ) | 451 | 432 | ||||||||||||||
Depreciation, Depletion and Amortization |
2,114 | 1,946 | 1,833 | |||||||||||||||
Goodwill Impairment |
- | 497 | - | |||||||||||||||
E&E Impairment |
138 | 86 | 50 | |||||||||||||||
Unrealized (Gain) Loss on Risk Management |
195 | (596 | ) | 415 | ||||||||||||||
Foreign Exchange (Gain) Loss, Net |
1,036 | 411 | 208 | |||||||||||||||
(Gain) Loss on Divestitures of Assets |
(2,392 | ) | (156 | ) | 1 | |||||||||||||
Other (Income) Loss, Net |
2 | (4 | ) | 2 | ||||||||||||||
Adjusted EBITDA |
2,084 | 3,791 | 4,036 | |||||||||||||||
Debt to Adjusted EBITDA |
3.1x | 1.4x | 1.2x | |||||||||||||||
Net Debt to Adjusted EBITDA |
|
1.2x |
|
|
1.2x |
|
|
1.0x |
|
Cenovus will maintain a high level of capital discipline and manage its capital structure to ensure sufficient liquidity through all stages of the economic cycle. To manage its capital structure, Cenovus may, among other actions, adjust capital and operating spending, adjust dividends paid to shareholders, purchase shares for cancellation pursuant to normal course issuer bids, issue new shares, issue new debt, draw down on its credit facilities or repay existing debt.
As at December 31, 2015, Cenovus had $4.0 billion available on its committed credit facility. In addition, Cenovus had in place a $1.5 billion Canadian base shelf prospectus and a US$2.0 billion U.S. base shelf prospectus, the availability of which are dependent on market conditions.
Under the committed credit facility, the Company is required to maintain a debt to capitalization ratio, not to exceed 65 percent. The Company is well below this limit.
As at December 31, 2015, Cenovus is in compliance with all of the terms of its debt agreements.
Cenovuss consolidated financial assets and financial liabilities consist of cash and cash equivalents, accounts receivable and accrued revenues, accounts payable and accrued liabilities, risk management assets and liabilities, available for sale financial assets, long-term receivables, short-term borrowings and long-term debt. Risk management assets and liabilities arise from the use of derivative financial instruments.
A) Fair Value of Non-Derivative Financial Instruments
The fair values of cash and cash equivalents, accounts receivable and accrued revenues, accounts payable and accrued liabilities, and short-term borrowings approximate their carrying amount due to the short-term maturity of those instruments.
The fair values of long-term receivables approximate their carrying amount due to the specific non-tradeable nature of these instruments.
Long-term debt is carried at amortized cost. The estimated fair values of long-term borrowings have been determined based on period-end trading prices of long-term borrowings on the secondary market (Level 2). As at December 31, 2015, the carrying value of Cenovuss long-term debt was $6,525 million and the fair value was $6,050 million (2014 carrying value $5,458 million, fair value $5,726 million).
Cenovus Energy Inc. | 45 | Consolidated Financial Statements |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2015
Available for sale financial assets are carried at fair value on the Consolidated Balance Sheets in other assets. Fair value is determined based on recent private placement transactions (Level 3) when available. The following table provides a reconciliation of changes in the fair value of available for sale financial assets:
As at December 31, | 2015 | 2014 | ||||||||
Fair Value, Beginning of Year |
32 | 32 | ||||||||
Acquisition of Investments |
2 | 4 | ||||||||
Reclassification of Equity Investments |
- | (4 | ) | |||||||
Change in Fair Value (1) |
8 | - | ||||||||
Fair Value, End of Year |
42 | 32 |
(1) | Unrealized gains and losses on available for sale financial assets are recorded in other comprehensive income. |
B) Fair Value of Risk Management Assets and Liabilities
The Companys risk management assets and liabilities consist of crude oil, condensate, natural gas and power purchase contracts, as well as interest rate swaps. Crude oil, condensate and natural gas contracts are recorded at their estimated fair value based on the difference between the contracted price and the period-end forward price for the same commodity, using quoted market prices or the period-end forward price for the same commodity extrapolated to the end of the term of the contract (Level 2). The fair value of power purchase contracts are calculated internally based on observable and unobservable inputs such as forward power prices in less active markets (Level 3). The unobservable inputs are obtained from third parties whenever possible and reviewed by the Company for reasonableness. The forward prices used in the determination of the fair value of the power purchase contracts as at December 31, 2015 range from $30.00 to $41.00 per megawatt hour. The fair value of interest rate swaps are calculated using external valuation models which incorporate observable market data, including quoted market prices and interest rate yield curves (Level 2).
Summary of Unrealized Risk Management Positions
2015 | 2014 | |||||||||||||||||||||||||||||||||
Risk Management | Risk Management | |||||||||||||||||||||||||||||||||
As at December 31, | Asset | Liability | Net | Asset | Liability | Net | ||||||||||||||||||||||||||||
Commodity Prices |
||||||||||||||||||||||||||||||||||
Crude Oil |
301 | 15 | 286 | 423 | 7 | 416 | ||||||||||||||||||||||||||||
Natural Gas |
- | - | - | 55 | - | 55 | ||||||||||||||||||||||||||||
Power |
- | 13 | (13) | - | 9 | (9 | ) | |||||||||||||||||||||||||||
301 | 28 | 273 | 478 | 16 | 462 | |||||||||||||||||||||||||||||
Interest Rate |
- | 2 | (2) | - | - | - | ||||||||||||||||||||||||||||
Total Fair Value |
301 | 30 | 271 | 478 | 16 | 462 |
The following table presents the Companys fair value hierarchy for risk management assets and liabilities carried at fair value:
As at December 31, | 2015 | 2014 | ||||||||
Prices Sourced From Observable Data or Market Corroboration (Level 2) |
284 | 471 | ||||||||
Prices Determined From Unobservable Inputs (Level 3) |
(13 | ) | (9 | ) | ||||||
271 | 462 |
Prices sourced from observable data or market corroboration refers to the fair value of contracts valued in part using active quotes and in part using observable, market-corroborated data. Prices determined from unobservable inputs refers to the fair value of contracts valued using data that is both unobservable and significant to the overall fair value measurement.
Cenovus Energy Inc. | 46 | Consolidated Financial Statements |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2015
The following table provides a reconciliation of changes in the fair value of Cenovuss risk management assets and liabilities:
As at December 31, | 2015 | 2014 | ||||||||
Fair Value of Contracts, Beginning of Year |
462 | (129 | ) | |||||||
Fair Value of Contracts Realized During the Year (1) |
(656 | ) | (66 | ) | ||||||
Change in Fair Value of Contracts in Place at Beginning of Year and Contracts Entered Into During the Year (2) |
461 | 662 | ||||||||
Unrealized Foreign Exchange Gain (Loss) on U.S. Dollar Contracts |
4 | (5 | ) | |||||||
Fair Value of Contracts, End of Year |
271 | 462 |
(1) | Includes a realized loss of $10 million related to power contracts (2014 - $4 million gain). |
(2) | Includes a decrease of $14 million related to power contracts (2014 - $10 million decrease). |
Financial assets and liabilities are only offset if Cenovus has the current legal right to offset and intends to settle on a net basis or settle the asset and liability simultaneously. Cenovus offsets risk management assets and liabilities when the counterparty, commodity, currency and timing of settlement are the same. No additional unrealized risk management positions are subject to an enforceable master netting arrangement or similar agreement that are not otherwise offset.
The following table provides a summary of the Companys offsetting risk management positions:
2015 | 2014 | |||||||||||||||||||||||||||||||||
Risk Management | Risk Management | |||||||||||||||||||||||||||||||||
As at December 31, | Asset | Liability | Net | Asset | Liability | Net | ||||||||||||||||||||||||||||
Recognized Risk Management Positions |
||||||||||||||||||||||||||||||||||
Gross Amount |
317 | 46 | 271 | 479 | 17 | 462 | ||||||||||||||||||||||||||||
Amount Offset |
(16) | (16 | ) | - | (1 | ) | (1 | ) | - | |||||||||||||||||||||||||
Net Amount per Consolidated Financial Statements |
301 | 30 | 271 | 478 | 16 | 462 |
The derivative liabilities do not have credit risk-related contingent features. Due to credit practices that limit transactions according to counterparties credit quality, the change in fair value through profit or loss attributable to changes in the credit risk of financial liabilities is immaterial.
Cenovus pledges cash collateral with respect to certain of these risk management contracts, which is not offset against the related financial liability. The amount of cash collateral required will vary daily over the life of these risk management contracts as commodity prices change. Additional cash collateral is required if, on a net basis, risk management payables exceed risk management receivables on a particular day. As at December 31, 2015, $26 million (2014 $12 million) was pledged as collateral, of which $5 million (2014 $7 million) could have been withdrawn.
C) Earnings Impact of (Gains) Losses From Risk Management Positions
For the years ended December 31, | 2015 | 2014 | 2013 | |||||||||||||
Realized (Gain) Loss (1) |
(656 | ) | (66 | ) | (122 | ) | ||||||||||
Unrealized (Gain) Loss (2) |
195 | (596 | ) | 415 | ||||||||||||
(Gain) Loss on Risk Management |
(461 | ) | (662 | ) | 293 |
(1) | Realized gains and losses on risk management are recorded in the operating segment to which the derivative instrument relates. |
(2) | Unrealized gains and losses on risk management are recorded in the Corporate and Eliminations segment. |
The Company is exposed to financial risks, including market risk related to commodity prices, foreign exchange rates, interest rates as well as credit risk and liquidity risk.
A) Commodity Price Risk
Commodity price risk arises from the effect that fluctuations of forward commodity prices may have on the fair value or future cash flows of financial assets and liabilities. To partially mitigate exposure to commodity price risk, the Company has entered into various financial derivative instruments.
Cenovus Energy Inc. | 47 | Consolidated Financial Statements |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2015
The use of these derivative instruments is governed under formal policies and is subject to limits established by the Board of Directors. The Companys policy is not to use derivative instruments for speculative purposes.
Crude Oil The Company has used fixed price swaps and costless collars to partially mitigate its exposure to the commodity price risk on its crude oil sales. In addition, Cenovus has entered into a limited number of swaps and futures to help protect against widening light/heavy crude oil price differentials.
Condensate The Company has used fixed price swaps to partially mitigate its exposure to the commodity price risk on its condensate purchases.
Natural Gas To partially mitigate the natural gas commodity price risk, the Company may enter into swaps, which fix the AECO or the New York Mercantile Exchange (NYMEX) price. To help protect against widening natural gas price differentials in various production areas, Cenovus may also enter into swaps to manage the price differentials between production areas and various sales points.
Power The Company has in place a Canadian dollar denominated derivative contract, which commenced January 1, 2007 for a period of 11 years, to manage a portion of its electricity consumption costs.
Net Fair Value of Risk Management Positions
As at December 31, 2015 | Notional Volumes | Term | Average Price | Fair Value | ||||||||||||||||
Crude Oil Contracts |
||||||||||||||||||||
Fixed Price Contracts |
||||||||||||||||||||
Brent Fixed Price |
17,000 bbls/d | January June 2016 | $75.80/bbl | 64 | ||||||||||||||||
Brent Fixed Price |
33,000 bbls/d | January June 2016 | US$47.59/bbl | 65 | ||||||||||||||||
Brent Fixed Price |
10,000 bbls/d | January December 2016 | US$66.93/bbl | 127 | ||||||||||||||||
Brent Fixed Price |
5,000 bbls/d | July December 2016 | $75.46/bbl | 13 | ||||||||||||||||
WCS Differential (1) |
31,600 bbls/d | January December 2016 | US$(13.96)/bbl | (9 | ) | |||||||||||||||
Brent Collars |
10,000 bbls/d | July December 2016 | |
US$45.55 US$56.55/bbl |
|
11 | ||||||||||||||
Other Financial Positions (2) |
17 | |||||||||||||||||||
Crude Oil Fair Value Position |
288 | |||||||||||||||||||
Condensate Purchase Contracts |
||||||||||||||||||||
Mont Belvieu Fixed Price |
3,000 bbls/d | January December 2016 | US$39.20/bbl | (2 | ) | |||||||||||||||
Power Purchase Contracts |
||||||||||||||||||||
Power Fair Value Position |
(13 | ) | ||||||||||||||||||
Interest Rate Swaps |
(2 | ) |
(1) Cenovus entered into fixed price swaps to protect against widening light/heavy price differentials for heavy crudes.
(2) Other financial positions are part of ongoing operations to market the Companys production.
Price Sensitivities Risk Management Positions
The following table summarizes the sensitivity of the fair value of Cenovuss risk management positions to fluctuations in commodity prices or interest rates, with all other variables held constant. Management believes the price and interest rate fluctuations identified in the table below are a reasonable measure of volatility. The impact of fluctuating commodity prices and interest rates on the Companys open risk management positions in place as at December 31, 2015 and 2014 could have resulted in unrealized gains (losses) impacting earnings before income tax as follows:
2015 | 2014 | |||||||||||||||||||||||||
Sensitivity Range | Increase | Decrease | Increase | Decrease | ||||||||||||||||||||||
Crude Oil Commodity Price |
± US$10 per bbl Applied to Brent and WTI Hedges |
(243 | ) | 245 | (145 | ) | 146 | |||||||||||||||||||
Crude Oil Differential Price |
± US$5 per bbl Applied to Differential Hedges Tied to Production |
80 | (80 | ) | 5 | (5 | ) | |||||||||||||||||||
Condensate Commodity Price |
± US$10 per bbl Applied to Condensate Hedges |
23 | (23 | ) | - | - | ||||||||||||||||||||
Natural Gas Commodity Price |
± US$1 per Mcf Applied to NYMEX and AECO Natural Gas Hedges |
- | - | (70 | ) | 70 | ||||||||||||||||||||
Power Commodity Price |
± $25 per MWHr Applied to Power Hedge |
19 | (19 | ) | 19 | (19 | ) | |||||||||||||||||||
Interest Rate Swaps |
± 50 Basis Points |
|
38 |
|
|
(46 |
) |
|
- |
|
|
- |
|
Cenovus Energy Inc. | 48 | Consolidated Financial Statements |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2015
B) Foreign Exchange Risk
Foreign exchange risk arises from changes in foreign exchange rates that may affect the fair value or future cash flows of Cenovuss financial assets or liabilities. As Cenovus operates in North America, fluctuations in the exchange rate between the U.S./Canadian dollar can have a significant effect on reported results.
As disclosed in Note 7, Cenovuss foreign exchange (gain) loss primarily includes unrealized foreign exchange gains and losses on the translation of the U.S. dollar debt issued from Canada and the translation of the U.S. dollar Partnership Contribution Receivable issued from Canada. As at December 31, 2015, Cenovus had US$4,750 million in U.S. dollar debt issued from Canada (2014 US$4,750 million) and US$nil related to the U.S. dollar Partnership Contribution Receivable (2014 US$nil). In respect of these financial instruments, the impact of changes in the U.S. to Canadian dollar exchange rate would have resulted in a change to foreign exchange (gain) loss as follows:
For the years ended December 31, | 2015 | 2014 | 2013 | |||||||
$0.01 Increase in the U.S. to Canadian Dollar Exchange Rate |
48 | 48 | 48 | |||||||
$0.01 Decrease in the U.S. to Canadian Dollar Exchange Rate |
(48) | (48) | (48) |
C) Interest Rate Risk
Interest rate risk arises from changes in market interest rates that may affect earnings, cash flows and valuations. Cenovus has the flexibility to partially mitigate its exposure to interest rate changes by maintaining a mix of both fixed and floating rate debt. In addition, to manage the Companys exposure to interest rate volatility, the Company may periodically enter into interest rate swap contracts related to future debt issuances. As at December 31, 2015, the Company had a notional amount of US$300 million in forward swaps.
As at December 31, 2015, the increase or decrease in net earnings for a one percentage point change in interest rates on floating rate debt amounts to $nil (2014 $nil, 2013 $nil). This assumes the amount of fixed and floating debt remains unchanged from the respective balance sheet dates.
D) Credit Risk
Credit risk arises from the potential that the Company may incur a loss if a counterparty to a financial instrument fails to meet its obligation in accordance with agreed terms. This credit risk exposure is mitigated through the use of the credit policy approved by the Audit Committee of the Board of Directors governing the Companys credit portfolio and with credit practices that limit transactions according to counterparties credit quality. Agreements are entered into with major financial institutions with investment grade credit ratings and with large commercial counterparties, most of which have investment grade credit ratings. A substantial portion of Cenovuss accounts receivable are with customers in the oil and gas industry and are subject to normal industry credit risks. As at December 31, 2015 and 2014, substantially all of the Companys accounts receivable were less than 60 days. As at December 31, 2015, 91 percent (2014 91 percent) of Cenovuss accounts receivable and financial derivative credit exposures are with investment grade counterparties. Cenovuss exposure to its counterparties is within credit policy tolerances.
As at December 31, 2015, Cenovus had one counterparty (2014 two counterparties) whose net settlement position individually account for more than 10 percent of the fair value of the outstanding in-the-money net financial and physical contracts by counterparty. The maximum credit risk exposure associated with accounts receivable and accrued revenues, risk management assets, and long-term receivables is the total carrying value.
E) Liquidity Risk
Liquidity risk is the risk that Cenovus will not be able to meet all of its financial obligations as they become due. Liquidity risk also includes the risk of not being able to liquidate assets in a timely manner at a reasonable price. Cenovus manages its liquidity risk through the active management of cash and debt and by maintaining appropriate access to credit, which may be impacted by the Companys credit ratings. As disclosed in Note 30, over the long term, Cenovus targets a Debt to Capitalization ratio between 30 and 40 percent and a Debt to Adjusted EBITDA of between 1.0 to 2.0 times to manage the Companys overall debt position.
Cenovus manages its liquidity risk by ensuring that it has access to multiple sources of capital including: cash and cash equivalents, cash from operating activities, undrawn credit facilities and availability under its shelf prospectuses. As at December 31, 2015, Cenovus had $4.1 billion in cash and cash equivalents, and $4.0 billion available on its committed credit facility. In addition, Cenovus had in place a $1.5 billion Canadian base shelf prospectus and a US$2.0 billion U.S. base shelf prospectus, the availability of which are dependent on market conditions.
Cenovus Energy Inc. | 49 | Consolidated Financial Statements |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2015
Undiscounted cash outflows relating to financial liabilities are:
2015 | Less than 1 Year | 1-3 Years | 4-5 Years | Thereafter | Total | |||||||||||||||||||||||
Accounts Payable and Accrued Liabilities |
1,702 | - | - | - | 1,702 | |||||||||||||||||||||||
Risk Management Liabilities (1) |
23 | 5 | 2 | - | 30 | |||||||||||||||||||||||
Long-Term Debt (2) |
349 | 2,847 | 493 | 8,721 | 12,410 | |||||||||||||||||||||||
Other (2) |
- | 3 | 1 | 4 | 8 | |||||||||||||||||||||||
2014 |
Less than 1 Year |
1-3 Years | 4-5 Years | Thereafter | Total | |||||||||||||||||||||||
Accounts Payable and Accrued Liabilities |
2,588 | - | - | - | 2,588 | |||||||||||||||||||||||
Risk Management Liabilities (1) |
12 | 4 | - | - | 16 | |||||||||||||||||||||||
Long-Term Debt (2) |
293 | 585 | 2,093 | 7,724 | 10,695 | |||||||||||||||||||||||
Other (2) |
- | 3 | 1 | 4 | 8 |
(1) Risk management liabilities subject to master netting agreements.
(2) Principal and interest, including current portion.
33. SUPPLEMENTARY CASH FLOW INFORMATION
For the years ended December 31, | 2015 | 2014 | 2013 | |||||||
Interest Paid |
330 | 335 | 409 | |||||||
Interest Received |
19 | 33 | 119 | |||||||
Income Taxes Paid |
933 | 46 | 133 |
34. COMMITMENTS AND CONTINGENCIES
A) Commitments
As part of normal operations, the Company has committed to certain amounts over the next five years and thereafter as follows:
2015 | 1 Year | 2 Years | 3 Years | 4 Years | 5 Years | Thereafter | Total | |||||||||||||||||||||||||||||||||
Transportation and Storage (1) |
702 | 715 | 780 | 774 | 901 | 23,537 | 27,409 | |||||||||||||||||||||||||||||||||
Operating Leases (Building Leases) |
116 | 120 | 156 | 153 | 151 | 2,647 | 3,343 | |||||||||||||||||||||||||||||||||
Product Purchases |
84 | 3 | - | - | - | - | 87 | |||||||||||||||||||||||||||||||||
Capital Commitments |
61 | 14 | 4 | - | - | - | 79 | |||||||||||||||||||||||||||||||||
Other Long-Term Commitments |
45 | 31 | 24 | 26 | 15 | 125 | 266 | |||||||||||||||||||||||||||||||||
Total Payments (2) |
1,008 | 883 | 964 | 953 | 1,067 | 26,309 | 31,184 | |||||||||||||||||||||||||||||||||
Fixed Price Product Sales |
55 | 3 | - | - | - | - | 58 | |||||||||||||||||||||||||||||||||
2014 | 1 Year | 2 Years | 3 Years | 4 Years | 5 Years | Thereafter | Total | |||||||||||||||||||||||||||||||||
Transportation and Storage (1) |
522 | 637 | 644 | 823 | 1,590 | 23,632 | 27,848 | |||||||||||||||||||||||||||||||||
Operating Leases (Building Leases) |
124 | 122 | 120 | 162 | 160 | 2,796 | 3,484 | |||||||||||||||||||||||||||||||||
Product Purchases |
101 | 7 | - | - | - | - | 108 | |||||||||||||||||||||||||||||||||
Capital Commitments |
90 | 55 | 11 | 2 | - | 46 | 204 | |||||||||||||||||||||||||||||||||
Other Long-Term Commitments |
58 | 24 | 21 | 15 | 13 | 116 | 247 | |||||||||||||||||||||||||||||||||
Total Payments (2) |
895 | 845 | 796 | 1,002 | 1,763 | 26,590 | 31,891 | |||||||||||||||||||||||||||||||||
Fixed Price Product Sales |
54 | 55 | 3 | - | - | - | 112 |
(1) Certain transportation commitments included are subject to regulatory approval.
(2) Contracts undertaken on behalf of the FCCL and WRB are reflected at Cenovuss 50 percent interest.
In 2015, net transportation commitments of $92 million were assumed upon the acquisition of the Companys crude-by-rail terminal.
As at December 31, 2015, there were outstanding letters of credit aggregating $64 million issued as security for performance under certain contracts (2014 $74 million).
Cenovus Energy Inc. | 50 | Consolidated Financial Statements |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2015
In addition to the above, Cenovuss commitments related to its risk management program are disclosed in Note 32.
B) Contingencies
Legal Proceedings
Cenovus is involved in a limited number of legal claims associated with the normal course of operations. Cenovus believes it has made adequate provisions for such legal claims. There are no individually or collectively significant claims.
Decommissioning Liabilities
Cenovus is responsible for the retirement of long-lived assets at the end of their useful lives. Cenovus has recorded a liability of $2,052 million, based on current legislation and estimated costs, related to its crude oil and natural gas properties, refining facilities and midstream facilities. Actual costs may differ from those estimated due to changes in legislation and changes in costs.
Income Tax Matters
The tax regulations and legislation and interpretations thereof in the various jurisdictions in which Cenovus operates are continually changing. As a result, there are usually a number of tax matters under review. Management believes that the provision for taxes is adequate.
Cenovus Energy Inc. | 51 | Consolidated Financial Statements |
Cenovus Energy Inc.
Supplementary Information Oil and Gas Activities (unaudited)
For the Year Ended December 31, 2015
(Canadian Dollars)
DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES TOPIC 932 EXTRACTIVE ACTIVITIES OIL AND GAS (unaudited)
The following select disclosures of Cenovus Energy Inc.s (Cenovus or the Company) reserves and other oil and gas information have been prepared in accordance with United States (U.S.) Financial Accounting Standards Board (FASB) Topic 932, Extractive Activities Oil & Gas and the U.S. disclosure requirements of the Securities and Exchange Commission (SEC).
All amounts pertaining to Cenovuss audited Consolidated Financial Statements are prepared in accordance with International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB). Unless otherwise noted, all dollars are in millions of Canadian dollars. All references to C$ 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 reserves be estimated using existing economic conditions (constant pricing). Cenovuss 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 Cenovuss share of future production from Canadian reserves to be materially different from that presented.
The reserves estimates included in this supplemental information are estimates only. There are numerous uncertainties inherent in estimating quantities of reserves, including many factors beyond the Companys control. In general, estimates of economically recoverable bitumen, crude oil 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 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. Cenovuss actual production, revenues, 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 volumes. Canadian reserves, as presented on a net basis, assume royalty rates in existence at the time the estimates were made.
Subsequent to December 31, 2015 no major discovery or other favourable or unfavourable event is believed to have caused a material change in the proved reserves as of that date.
The reserves data contained herein is dated February 9, 2016 with an effective date of December 31, 2015.
2 | ||
Cenovus Energy Inc. | Supplementary Information Oil and Gas Activities (unaudited) |
OIL AND GAS RESERVE INFORMATION
All of Cenovuss reserves are located in Alberta and Saskatchewan, Canada.
Net Proved Reserves (Cenovus Share After Royalties)(1)(2)(3)
Average Fiscal-Year Prices
Bitumen (MMbbls)(4) |
Crude Oil and Natural Gas Liquids (MMbbls)(4) |
Natural Gas (Bcf)(4) |
||||||||||
2014 |
||||||||||||
Beginning of year |
1,455 | 251 | 795 | |||||||||
Revisions and improved recovery |
8 | (2 | ) | 183 | ||||||||
Extensions and discoveries |
83 | 22 | 24 | |||||||||
Purchase of reserves in place |
- | - | 2 | |||||||||
Sale of reserves in place |
- | (10 | ) | (5 | ) | |||||||
Production |
(43 | ) | (25 | ) | (179 | ) | ||||||
End of year |
1,503 | 236 | 820 | |||||||||
Developed |
180 | 183 | 817 | |||||||||
Undeveloped |
1,323 | 53 | 3 | |||||||||
Total |
1,503 | 236 | 820 | |||||||||
2015 | ||||||||||||
Beginning of year |
1,503 | 236 | 820 | |||||||||
Revisions and improved recovery |
336 | (7 | ) | (73 | ) | |||||||
Extensions and discoveries |
164 | 1 | 6 | |||||||||
Purchase of reserves in place |
- | - | - | |||||||||
Sale of reserves in place |
- | (18 | ) | (54 | ) | |||||||
Production |
(50 | ) | (22 | ) | (160 | ) | ||||||
End of year |
1,953 | 190 | 539 | |||||||||
Developed |
282 | 157 | 538 | |||||||||
Undeveloped |
1,671 | 33 | 1 | |||||||||
Total |
1,953 | 190 | 539 |
(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) | Natural gas liquids reserves are individually insignificant and have been included with crude oil reserves. |
(4) | Millions of barrels is abbreviated as MMbbls; Billion cubic feet is abbreviated as Bcf. |
3 | ||
Cenovus Energy Inc. | Supplementary Information Oil and Gas Activities (unaudited) |
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 Cenovuss annual future production from 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 Cenovuss 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 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 Cenovuss enhancing the netback price of the Companys 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 | Natural Gas | |||||||||||||||||||||
WTI(1) Cushing (US$/bbl) |
WCS(2) (C$/bbl) |
Edmonton Par (C$/bbl) |
Henry Hub (US$/MMBtu) |
AECO(3) (C$/MMBtu) |
||||||||||||||||||
2015 |
50.28 | 46.78 | 59.41 | 2.58 | 2.69 | |||||||||||||||||
2014 |
95.55 | 84.27 | 97.60 | 4.34 | 4.63 |
(1) | WTI is an abbreviation for West Texas Intermediate. |
(2) | WCS is an abbreviation for Western Canadian Select. |
(3) | AECO is an abbreviation for Alberta Energy Company Operations. |
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
($ millions) | 2015 | 2014 | ||||||
Future cash inflows |
73,219 | 122,882 | ||||||
Less future: |
||||||||
Production costs |
34,339 | 41,292 | ||||||
Development costs |
14,626 | 15,643 | ||||||
Decommissioning liability payments |
3,706 | 960 | ||||||
Income taxes |
4,432 | 14,935 | ||||||
Future net cash flows |
16,116 | 50,052 | ||||||
Less 10 percent annual discount for estimated timing of cash flows |
10,090 | 31,065 | ||||||
Discounted future net cash flows |
6,026 | 18,987 | ||||||
Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
|
| |||||||
($ millions) | 2015 | 2014 | ||||||
Balance, beginning of year |
18,987 | 13,992 | ||||||
Changes resulting from: |
||||||||
Sales of oil and gas produced during the period |
(2,054 | ) | (3,947 | ) | ||||
Extensions, discoveries and improved recovery, net of related costs |
535 | 1,498 | ||||||
Purchases of proved reserves in place |
- | 4 | ||||||
Sales of proved reserves in place |
(87 | ) | (134 | ) | ||||
Net change in prices and production costs |
(20,942 | ) | 6,414 | |||||
Revisions to quantity estimates |
1,021 | 361 | ||||||
Accretion of discount |
2,441 | 1,809 | ||||||
Previously estimated development costs incurred net of change in future development costs |
2,636 | 279 | ||||||
Asset Retirement Obligation |
(313 | ) | (15 | ) | ||||
Other |
(186 | ) | 48 | |||||
Net change in income taxes |
3,988 | (1,322 | ) | |||||
Balance, end of year |
6,026 | 18,987 |
4 | ||
Cenovus Energy Inc. | Supplementary Information Oil and Gas Activities (unaudited) |
OTHER FINANCIAL INFORMATION
Results of Operations
($ millions) | 2015 | 2014 | ||||
Oil and gas sales to external customers, net of royalties, transportation and blending and realized risk management |
2,829 | 4,546 | ||||
Intersegment sales |
335 | 812 | ||||
3,164 | 5,358 | |||||
Less: |
||||||
Operating costs, production and mineral taxes, and accretion of decommissioning liabilities(1) |
1,235 | 1,512 | ||||
Depreciation, depletion and amortization |
1,845 | 1,707 | ||||
Goodwill impairment |
- | 497 | ||||
Exploration expense |
138 | 86 | ||||
Operating income |
(54 | ) | 1,556 | |||
Income taxes |
(14 | ) | 517 | |||
Results of operations |
(40 | ) | 1,039 |
(1) | Employee stock-based compensation costs previously included in operating expense have been reclassified to general and administrative expense. As a result, for the year ended December 31, 2014, $17 million was reclassified. |
Capitalized Costs
($ millions) | 2015 | 2014 | ||||
Proved oil and gas properties |
31,812 | 32,030 | ||||
Unproved oil and gas properties (2) |
1,575 | 1,625 | ||||
Total capital cost |
33,387 | 33,655 | ||||
Accumulated depreciation, depletion and amortization |
19,185 | 17,386 | ||||
Net capitalized costs |
14,202 | 16,269 | ||||
(2) Unproved oil and gas properties include exploration and evaluation assets for which no proved reserves have been recognized.
Costs Incurred
| ||||||
($ millions) | 2015 | 2014 | ||||
Acquisitions |
||||||
Unproved |
4 | 16 | ||||
Proved |
- | 2 | ||||
Total acquisitions |
4 | 18 | ||||
Exploration costs |
66 | 159 | ||||
Development costs |
1,360 | 2,623 | ||||
Total costs incurred |
1,430 | 2,800 |
5 | ||
Cenovus Energy Inc. | Supplementary Information Oil and Gas Activities (unaudited) |
ADDITIONAL DISCLOSURE
Certifications and Disclosure Regarding Controls and Procedures.
(a) | Certifications. See Exhibits 99.1, 99.2, 99.3 and 99.4 to this annual report on Form 40-F. |
(b) | Disclosure Controls and Procedures. As of the end of the registrants fiscal year ended December 31, 2015, an evaluation of the effectiveness of the registrants disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (the Exchange Act)) was carried out by the registrants management with the participation of the principal executive officer and principal financial officer. Based upon that evaluation, the registrants principal executive officer and principal financial officer have concluded that as of the end of that fiscal year, the registrants disclosure controls and procedures are effective to ensure that information required to be disclosed by the registrant in reports that it files or submits under the Exchange Act is (i) recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commissions (the Commission) rules and forms and (ii) accumulated and communicated to the registrants management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. |
It should be noted that while the registrants principal executive officer and principal financial officer believe that the registrants disclosure controls and procedures provide a reasonable level of assurance that they are effective, they do not expect that the registrants disclosure controls and procedures or internal control over financial reporting will prevent all errors and fraud. A control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met.
(c) | Managements Annual Report on Internal Control Over Financial Reporting. The required disclosure is included in the Report of Management that accompanies the registrants Consolidated Financial Statements for the fiscal year ended December 31, 2015, filed as part of this annual report on Form 40-F. |
(d) | Attestation Report of the Registered Public Accounting Firm. The required disclosure is included in the Report of Independent Registered Public Accounting Firm that accompanies the registrants Consolidated Financial Statements for the fiscal year ended December 31, 2015, filed as part of this annual report on Form 40-F. |
(e) | Changes in Internal Control Over Financial Reporting. During the fiscal year ended December 31, 2015, there was no change in the registrants internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, the registrants internal control over financial reporting. |
Notices Pursuant to Regulation BTR.
None.
Audit Committee Financial Expert.
The registrants board of directors has determined that Colin Taylor, a member of the registrants audit committee, qualifies as an audit committee financial expert (as such term is defined in paragraph (8) of General Instruction B to Form 40-F), and is independent as that term is defined in the rules of the New York Stock Exchange.
Code of Ethics.
The registrant has adopted a code of ethics (as that term is defined in paragraph (9) of General Instruction B to Form 40-F), entitled the Code of Business Conduct & Ethics, that applies to all of its employees, including its principal executive officer, principal financial officer, principal accounting officer or controller, and persons performing similar functions.
The Code of Business Conduct & Ethics (the Code) is available for viewing on the registrants website at www.cenovus.com, and is available in print to any person without charge, upon request. Requests for copies of the Code should be made by contacting the registrants Corporate Secretarial Department, Cenovus Energy Inc., 2600, 500 Centre Street S.E., Calgary, Alberta, Canada T2G 1A6. Information on or connected to our website, even if referred to herein, does not constitute part of this annual report on Form 40-F.
Since the adoption of the Code, there have not been any waivers, including implicit waivers, granted from any provision of the Code. There were no amendments to the Code in the fiscal year ended December 31, 2015.
3
Principal Accountant Fees and Services.
The required disclosure is included under the heading Audit Committee External Auditor Service Fees in the registrants Annual Information Form for the fiscal year ended December 31, 2015, filed as part of this annual report on Form 40-F.
Pre-Approval Policies and Procedures and Percentage of Services Approved by Audit Committee.
The required disclosure is included under the heading Audit Committee Pre-Approval Policies and Procedures and Audit Committee External Auditor Service Fees in the registrants Annual Information Form for the fiscal year ended December 31, 2015, filed as part of this annual report on Form 40-F. None of the services therein were approved by the Audit Committee pursuant to paragraph (c)(7)(i)(C) of Rule 2-01 of Regulation S-X.
Off-Balance Sheet Arrangements.
The registrant does not have any off-balance sheet arrangements (as that term is defined in paragraph (11) of General Instruction B to Form 40-F) that have or are reasonably likely to have a current or future effect on its financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.
Tabular Disclosure of Contractual Obligations.
The required disclosure is included under the heading Liquidity and Capital Resources - Contractual Obligations and Commitments in the registrants Managements Discussion and Analysis for the fiscal year ended December 31, 2015, filed as part of this annual report on Form 40-F.
Identification of the Audit Committee.
The registrant has a separately-designated standing audit committee established in accordance with Section 3(a)(58)(A) of the Exchange Act. The members of the audit committee are: Patrick D. Daniel, Steven F. Leer, Valerie A.A. Nielsen and Colin Taylor.
Mine Safety Disclosure.
Not applicable.
4
UNDERTAKING AND CONSENT TO SERVICE OF PROCESS
A. Undertaking
The registrant undertakes to make available, in person or by telephone, representatives to respond to inquiries made by the Commission staff, and to furnish promptly, when requested to do so by the Commission staff, information relating to: the securities registered pursuant to Form 40-F; the securities in relation to which the obligation to file an annual report on Form 40-F arises; or transactions in said securities.
B. Consent to Service of Process
(1) | The registrant has previously filed a Form F-X in connection with the class of securities in relation to which the obligation to file this report arises. |
(2) | Any change to the name or address of the agent for service of process of the registrant shall be communicated promptly to the Commission by an amendment to the Form F-X referencing the file number of the registrant. |
SIGNATURES
Pursuant to the requirements of the Exchange Act, the Registrant certifies that it meets all of the requirements for filing on Form 40-F and has duly caused this annual report to be signed on its behalf by the undersigned, thereto duly authorized.
Date: February 11, 2016 | CENOVUS ENERGY INC. | |||||||||
By: | /s/ Ivor M. Ruste |
|||||||||
Name: | Ivor M. Ruste | |||||||||
Title: | Executive Vice-President & Chief Financial Officer |
EXHIBIT INDEX
Exhibits | Documents | |
99.1 |
Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934 | |
99.2 |
Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934 | |
99.3 |
Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350 | |
99.4 |
Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350 | |
99.5 |
Consent of PricewaterhouseCoopers LLP | |
99.6 |
Consent of McDaniel & Associates Consultants Ltd. | |
99.7 |
Consent of GLJ Petroleum Consultants Ltd. | |
99.8 |
Statement of Contingent and Prospective Resources |
Exhibit 99.1
Certification of Chief Executive Officer
Pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934
I, Brian C. Ferguson, certify that:
1. | I have reviewed this annual report on Form 40-F of Cenovus Energy Inc.; |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report; |
4. | The issuers other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have: |
(a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
(b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
(c) | Evaluated the effectiveness of the issuers disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
(d) | Disclosed in this report any change in the issuers internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuers internal control over financial reporting; and |
5. | The issuers other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuers auditors and the audit committee of the issuers board of directors (or persons performing the equivalent functions): |
(a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuers ability to record, process, summarize and report financial information; and |
(b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuers internal control over financial reporting. |
Date: February 11, 2016
/s/ Brian C. Ferguson |
||
Brian C. Ferguson | ||
President & Chief Executive Officer | ||
(Principal Executive Officer) |
Exhibit 99.2
Certification of Chief Financial Officer
Pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934
I, Ivor M. Ruste, certify that:
1. | I have reviewed this annual report on Form 40-F of Cenovus Energy Inc.; |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report; |
4. | The issuers other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have: |
(a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
(b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
(c) | Evaluated the effectiveness of the issuers disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
(d) | Disclosed in this report any change in the issuers internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuers internal control over financial reporting; and |
5. | The issuers other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuers auditors and the audit committee of the issuers board of directors (or persons performing the equivalent functions): |
(a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuers ability to record, process, summarize and report financial information; and |
(b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuers internal control over financial reporting. |
Date: February 11, 2016
/s/ Ivor M. Ruste |
||
Ivor M. Ruste | ||
Executive Vice-President & Chief Financial Officer | ||
(Principal Financial Officer) |
Exhibit 99.3
Certification Pursuant to 18 U.S.C. Section 1350, As Adopted
Pursuant to Section 906 of the Sarbanes Oxley Act of 2002
In connection with the annual report of Cenovus Energy Inc. (the Company) on Form 40F for the year ended December 31, 2015, as filed with the Securities and Exchange Commission on the date hereof (the Report), I, Brian C. Ferguson, President & Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:
1. | The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and |
2. | The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. |
February 11, 2016
By: | /s/ Brian C. Ferguson |
|||
Brian C. Ferguson | ||||
President & Chief Executive Officer |
Exhibit 99.4
Certification Pursuant to 18 U.S.C. Section 1350, As Adopted
Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
In connection with the annual report of Cenovus Energy Inc. (the Company) on Form 40F for the year ended December 31, 2015, as filed with the Securities and Exchange Commission on the date hereof (the Report), I, Ivor M. Ruste, Executive Vice-President & Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:
1. | The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and |
2. | The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. |
February 11, 2016
By: | /s/ Ivor M. Ruste |
|||
Ivor M. Ruste | ||||
Executive Vice-President & Chief Financial Officer |
Exhibit 99.5
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We hereby consent to the inclusion in this Annual Report on Form 40-F for the year ended December 31, 2015 of Cenovus Energy Inc. of our report dated February 10, 2016, relating to the Consolidated Financial Statements of Cenovus Energy Inc., which comprise the Consolidated Balance Sheets as at December 31, 2015 and December 31, 2014 and the Consolidated Statements of Earnings, Comprehensive Income, Shareholders Equity and Cash Flows for each of the three years in the period ended December 31, 2015 and the related notes and to the effectiveness of internal control over financial reporting of Cenovus Energy Inc. as at December 31, 2015, which appears in this Annual Report.
We also consent to the incorporation by reference in the Registration Statements on Form S-8 (File No. 333-163397), Form F-3D (File No. 333-202165), and Form F-10 (File No. 333-196696) of Cenovus Energy Inc. of our report dated February 10, 2016 referred to above. We also consent to reference to PricewaterhouseCoopers LLP under the heading Interests of Experts, which appears in the Annual Information Form included in this Annual Report on Form 40-F, which is incorporated by reference in such Registration Statements.
/s/ PricewaterhouseCoopers LLP |
Calgary, Alberta
February 11, 2016
Exhibit 99.6
CONSENT OF INDEPENDENT PETROLEUM ENGINEER
We hereby consent to the use and reference to our name and reports evaluating (i) a portion of Cenovus Energy Inc. oil and gas reserves data, including estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2015, estimated using forecast prices and costs, and (ii) the contingent resources and prospective resources of Cenovus Energy Inc. as at December 31, 2015, estimated using forecast prices and costs, and the information derived from our reports, as described or incorporated by reference in Cenovus Energy Inc.s annual report on Form 40-F for the year ended December 31, 2015 and Cenovus Energy Inc.s registration statements on Form S-8 (File No. 333-163397), Form F-3D (File No. 333-202165), and Form F-10 (File No. 333-196696), filed with the United States Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, as amended or the Securities Act of 1933, as amended, as applicable.
MCDANIEL & ASSOCIATES CONSULTANTS LTD. | ||
/s/ P.A. Welch |
||
P.A. Welch, P. Eng. | ||
President & Managing Director | ||
Calgary, Alberta | ||
February 11, 2016 |
Exhibit 99.7
CONSENT OF INDEPENDENT PETROLEUM ENGINEER
We hereby consent to the use and reference to our name and report evaluating a portion of Cenovus Energy Inc. oil and gas reserves data, including estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2015, estimated using forecast prices and costs, and the information derived from our reports, as described or incorporated by reference in Cenovus Energy Inc.s annual report on Form 40-F for the year ended December 31, 2015 and Cenovus Energy Inc.s registration statements on Form S-8 (File No. 333-163397), Form F-3D (File No. 333-202165) and Form F-10 (File No. 333-196696), filed with the United States Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, as amended or the Securities Act of 1933, as amended, as applicable.
GLJ PETROLEUM CONSULTANTS LTD. | ||
/s/ Keith M. Braaten |
||
Keith M. Braaten, P. Eng | ||
President & CEO | ||
Calgary, Alberta | ||
February 11, 2016 |
Exhibit 99.8
Cenovus Energy Inc.
Statement of Contingent and Prospective Resources
For the Year Ended December 31, 2015
February 10, 2016
STATEMENT OF CONTINGENT AND PROSPECTIVE RESOURCES
This document contains information relating to estimates of economic bitumen contingent resources and bitumen prospective resources of Cenovus Energy Inc. (Cenovus or the Company) as at December 31, 2015.
Cenovus retained McDaniel & Associates Consultants Ltd. (McDaniel) to evaluate and prepare reports on the bitumen contingent and prospective resources of the Company. The McDaniel resources evaluations were conducted using petrophysical, geological, and engineering data. Processes and procedures are in place to ensure that McDaniel is in receipt of all relevant information. Contingent and prospective resources were estimated using fundamental data in volumetric calculations to estimate the in-place bitumen quantities, combined with development and performance from analog oil sands reservoirs. The oil sands assets currently producing from the McMurray-Wabiskaw formation including Foster Creek and Christina Lake were used as performance analogs for contingent and prospective resources estimation within these areas. Other regional analogs were used to estimate Cenovuss contingent and prospective resources in the Grand Rapids formation at the Greater Pelican Region, in the McMurray formation at the Telephone Lake property, and in the Clearwater formation at the Foster Creek Region. McDaniel also tested contingent resources for economic viability using McDaniels January 1, 2016 forecast of prices and inflation, the same forecast which was used to evaluate the Companys reserves (refer to Pricing Assumptions in Cenovuss Annual Information Form for the year ended December 31, 2015).
BITUMEN BEST ESTIMATE ECONOMIC CONTINGENT AND PROSPECTIVE RESOURCES
Company Interest (billions of barrels) |
December 31, 2015 |
December 31,
| ||||
Before | After | |||||
Economic Contingent Resources (2) | Royalties | Royalties | ||||
By Project Maturity Subclass: |
||||||
Development pending |
||||||
Christina Lake |
0.8 | 0.6 | ||||
Foster Creek |
1.1 | 0.9 | ||||
Borealis |
2.6 | 2.2 | ||||
Pelican Lake |
1.7 | 1.5 | ||||
Total |
6.2 | 5.2 | ||||
Development unclarified |
||||||
Borealis |
3.1 | 2.6 | ||||
Total Economic Contingent Resources |
9.3 | 7.8 | 9.3 | |||
Prospective Resources (3) |
||||||
By Project Maturity Subclass: |
||||||
Prospect |
||||||
Best Estimate |
7.4 | N/A | 7.5 |
(1) | Subclasses and after royalty volumes for contingent resources were not disclosed for year-end 2014. |
(2) | There is uncertainty that it will be commercially viable to produce any portion of the contingent resources. |
(3) | There is no certainty that any portion of the prospective resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the prospective resources. Prospective resources are not evaluated for economics, so after royalty volumes are not known. |
Bitumen best estimate economic contingent resources are virtually unchanged from year-end 2014. Bitumen best estimate prospective resources are one percent lower than in 2014.
EVALUATION BASIS
The evaluation assumes that the majority of Cenovuss bitumen resources will be recovered and produced using established steam assisted gravity drainage (SAGD) technology, with only a minor portion of the Companys resources likely to be developed using cyclic steam stimulation (CSS), also an established technology. SAGD involves injecting steam through horizontal wells drilled into the bitumen formation and recovering heated bitumen and water from producing wells located below the injection wells. CSS involves injecting steam into a well and then producing heated bitumen and water from the same wellbore. Such alternating injection and production cycles are repeated a number of times for a given wellbore. Both of these bitumen recovery technologies have a surface footprint comparable to conventional crude oil production operations. Cenovus has no bitumen resources that require mining techniques for recovery.
All of Cenovuss disclosed contingent and prospective resources are associated with clastic or sandstone formations. Cenovus has also identified significant amounts of bitumen in the Grosmont carbonate formation for which the Company has extensive mineral rights. Pilot testing of the SAGD recovery process in carbonates has been conducted in the Grosmont carbonate formation several miles away from Cenovuss lands, but commercial viability has yet to be established. Contingent resources in the carbonates are not included in the totals above.
Cenovus Energy Inc. | 1 Statement of Contingent and Prospective Resources |
ESTIMATION RISKS
Contingent and prospective resources results are estimates only. There are numerous risks and uncertainties associated with recovery of such resources, including many factors beyond the Companys control. In general, estimates of contingent and prospective resources are based upon a number of variable factors and assumptions, including but not limited to: product prices; future operating and capital costs and the assumed effects of regulation by governmental agencies, including royalty payments and taxes; initial production rates; production decline rates; and the availability, proximity and capacity of crude oil and natural gas gathering systems, pipelines, rail transportation and processing facilities, all of which may vary considerably from actual results. In addition, there are contingencies that prevent resources from being classified as reserves. There is uncertainty that it will be commercially viable to produce any portion of the contingent resources. Prospective resources are subject to similar contingencies and are also undiscovered, meaning that subsequent drilling may demonstrate actual results which may vary significantly from projected results. There is no certainty that any portion of the prospective resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the prospective resources. Actual results may vary significantly from these estimates and such variances could be material.
DEFINITIONS AND CENOVUSS APPLICATION
The following terminology, consistent with the Canadian Oil and Gas Evaluation (COGE) Handbook and guidance from Canadian securities regulators, was used to prepare the disclosure of contingent and prospective resources:
● | 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. Cenovus has chosen to not disclose contingent resource volumes which are subject to technology under development, as commercial viability has yet to be established for the recovery of these volumes.
● | Economic contingent resources are those contingent resources that are currently economically recoverable based on specific forecasts of commodity prices and inflation. Only those bitumen contingent resources based on established technology and determined to be economic using McDaniels forecast of prices and inflation are disclosed here. |
● | Contingencies, which must be overcome to enable the reclassification of contingent resources as reserves, can be categorized as economic, non-technical and technical. The COGE 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 Cenovuss disclosed economic contingent resources do not include economic contingencies. |
Cenovuss bitumen contingent resources are located in four general regions: Foster Creek, Christina Lake, Borealis, and Greater Pelican. At Foster Creek and Christina Lake, Cenovus has economic contingent resources located outside the currently approved project areas. Regulatory approval to expand a project area is necessary to enable the reclassification of these economic contingent resources as reserves. The timing of applications for such approvals is dependent on the rate of development drilling, which ties to an orderly development plan to maximize utilization of steam generation facilities and ultimately optimize production, capital utilization and value.
In the Borealis Region, Cenovus received regulatory approval for a development project at the Telephone Lake property which will help facilitate the reclassification of certain economic contingent resources to reserves. Other areas in the Borealis Region require additional results from delineation drilling and seismic activity to submit regulatory applications for development projects. Stratigraphic test well drilling and seismic activity are continuing in these areas to bring them to project readiness. Currently, sufficient pipeline capacity is also considered a contingency.
In the Greater Pelican Region, Cenovus received regulatory approval for a development project at the Grand Rapids property. Pilot project work was underway to validate technical assumptions and examine optimal development strategies, however, as of February 2016 further activity in respect of the pilot project has been deferred in response to the current low commodity price environment. Further reclassification of contingent resources to reserves in the Greater Pelican Region is contingent upon establishing productivity at commercial rates and further regulatory approval for development expansions.
Cenovus Energy Inc. | 2 Statement of Contingent and Prospective Resources |
● | Prospective resources are those quantities of bitumen estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective resources have both an associated chance of discovery and a chance of development. Prospective resources are further subdivided in accordance with the level of certainty associated with recoverable estimates, assuming their discovery and development, and may be subclassified based on project maturity. Estimates of prospective resources have not been adjusted for risk based on the chance of discovery or the chance of development. |
● | 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 identified as best estimate have a 50 percent probability that the actual quantities recovered will equal or exceed the estimate. |
● | Project maturity subclasses are subclassifications of reserves, contingent and prospective resources which help identify a projects chance of commerciality. The estimation of reserves and resources must always be done in the context of a project, defined as an activity or set of activities that define the basis for the assessment and classification of reserves and resources. Recognized subclasses for contingent resources include development pending, development on hold, development unclarified, and development not viable. Characteristics of these subclasses are as follows: |
¡ | Development pending: resolution of the final conditions for development is being actively pursued, indicating there is a high chance of development; |
¡ | Development on hold: there are major non-technical contingencies to be resolved that are usually beyond the control of the operator, although there is a reasonable chance of development; |
¡ | Development unclarified: the evaluation is incomplete and there is ongoing activity to resolve any risks or uncertainties; and |
¡ | Development not viable: no further data acquisition or evaluation is currently planned, resulting in a low chance of development. |
Cenovuss contingent resources located in the Christina Lake and Foster Creek areas are in close proximity to existing production facilities, with capacity scheduled to accommodate the associated production. These projects are subclassified as development pending. Cenovus has received approvals to proceed with development of the Telephone Lake property in the Borealis Region and the Grand Rapids formation in the Greater Pelican Region. These projects are also subclassified as development pending. Projects in the remainder of the Borealis Region are still under appraisal and evaluation, and are subclassified as development unclarified.
Projects which are uneconomic and subclassified as development not viable, are not disclosed.
Subclasses for prospective resources include:
¡ | Play: a family of geologically similar fields, prospects, discoveries and leads; |
¡ | Lead: a potential accumulation within a play that requires more data acquisition and/or evaluation in order to be called a prospect; and |
¡ | Prospect: a potential accumulation within a play that is sufficiently well defined to represent a viable drilling target. |
All of Cenovuss prospective resources are proximal to existing reserves and/or contingent resources and represent viable drilling targets. They are all subclassified as prospects.
PROJECT CHARACTERIZATION
Cenovus has consolidated its contingent and prospective resources into four regional areas: Christina Lake, Foster Creek, Borealis, and Greater Pelican. Within these areas are multiple projects at various levels of advancement. The contingent resources at Christina Lake and Foster Creek are located in areas which are geological extensions of the current SAGD development, and are expected to be developed in sequence as existing development expands out to those areas.
At Borealis there are also several projects, with only Telephone Lake being the subject of active development planning. An initial development project has received Alberta Energy Regulator (AER) approval, with future extension projects undergoing evaluation. Additional projects in the Borealis Region have been identified, but there is insufficient data to construct well-defined development plans. Tentative plans have been evaluated, however, additional data may lead to significant variation of these plans.
At Pelican Lake, a development plan has also been approved by the AER, leading to recognition of probable reserves within the approved development area. The contingent resources are an extension of the probable reserves, but are contingent on establishing satisfactory reservoir productivity. A pilot project to address productivity was underway, however, as of February 2016 further activity has been deferred in response to the current low commodity price environment.
Cenovus Energy Inc. | 3 Statement of Contingent and Prospective Resources |
The following table summarizes the project maturity sub-classes in each of the regional areas.
Region | Project Maturity Subclass |
Evaluation Scenario Status |
Capital to reach Commercial Production (1) $MM |
Timing of
First Production |
Recovery Technology | |||||
Christina Lake |
Development pending |
Development/ Pre-development |
230 - 870 | 2022 - 2048 | SAGD | |||||
Foster Creek |
Development pending |
Development/ Pre-development | 80 1,330 | 2024 - 2034 | SAGD/CSS | |||||
Borealis |
Development pending Development unclarified |
Development - Telephone Lake Conceptual All remaining projects |
900 2,800 | 2020 - 2028 | SAGD | |||||
Pelican Lake |
Development pending |
Pre-development | 2,830 | 2022 | SAGD |
(1) | McDaniel capital incorporates 2% per year inflation. |
The range of timing indicated for first production and cost to achieve commercial production reflects the range of projects identified in each region, and is a function of the relative priority placed on extending the reach of the existing development out to those projects. Project timing is also a function of the availability of capital to commence development activity. Capital to reach commercial production shown in the table above is primarily for infrastructure and facilities development, and does not include the significant amount of sustaining capital required to drill additional SAGD well pairs within each project to build and sustain production at project design rates.
The Telephone Lake and Grand Rapids projects are stand-alone, greenfield developments. These projects have received regulatory approval to proceed, with continuing delineation, engineering work and infrastructure development underway although as of February 2016 further activity in respect of the SAGD pilot at Grand Rapids has been deferred in response to the current low commodity price environment. Reservoir knowledge gained from existing operations is continually being reviewed for its potential impact on the optimization of these new developments. Typically, the timing of first commercial production from receipt of regulatory approval is five to eight years.
The uncertain timing of when technologies under development will become established, such as SAGD in carbonates and fireflooding in clastic bitumen deposits, and the uncertain timing of when economic viability might be established has led Cenovus to disclose only those contingent resources whose development is pending, on hold, or unclarified, which are not subject to technology under development, and which are economically viable.
RESERVES AND RESOURCES RECONCILIATION
The systematic progression of Cenovuss bitumen resources, from prospective to contingent resources and then to reserves, and ultimately to production, was deliberately slowed in 2015 as low commodity prices limited availability of delineation capital. For example, most stratigraphic wells drilled in 2015 were focused on supporting conversion of reserves to production at Christina Lake and Foster Creek, resulting in negligible prospective and contingent resources reclassification. Consequently, bitumen best estimate economic contingent resources for 2015 remained virtually unchanged at 9.3 billion barrels.
An annual reconciliation of reclassifications is shown in the following table:
Bitumen Proved plus Probable Reserves, Contingent and Prospective Resources
Reconciliation and Category Movements
Company Interest Before Royalties (billions of barrels) |
Proved plus Probable Reserves |
Best Estimate Contingent Resources (1) |
Best Estimate Prospective Resources (2) |
|||||||||
As at December 31, 2014 |
3.300 | 9.3 | 7.5 | |||||||||
Transfers between Categories |
||||||||||||
Additions from Other Resources Categories |
- | - | - | |||||||||
Reductions to Other Resources Categories |
- | - | - | |||||||||
Additions and Revisions Net of Transfers |
0.049 | 0.0 | -0.1 | |||||||||
Net Acquisitions and Divestitures |
- | - | - | |||||||||
Production |
(0.051) | - | - | |||||||||
As at December 31, 2015 |
3.298 | 9.3 | 7.4 |
(1) | There is uncertainty that it will be commercially viable to produce any portion of the contingent resources. |
(2) | There is no certainty that any portion of the prospective resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the prospective resources. Prospective resources are not screened for economic viability. |
Cenovus Energy Inc. | 4 Statement of Contingent and Prospective Resources |
@IB^?A5#(?0)A_@W82L/BQ\1WKNO]+;@7(9T[!:5< ";B<0+W1ZC'=JGB
M_@I6W@"E3#Z4,T]&ON0>A KJ%Y^#4FKGWH &[E3T-9J&G:FD-[+IL!3/7 *U_"62$HSF76KVTU:*R7#MOJ??
M(A"PZ>=6J=Z<=ZJSA7^<%KC>RO>EJ:S8[-C4JD5G$MC>L&YH,][^8TITBV-+
M1.N4O WR.AYG\NNWYMW
7GDXP
U:F3/;1Q>J#W]L^3D<,&KHN5%SMBW-KO#3Q.JC[FN:?S0GKXBL
MYE,@*\I
M'3NT["!@0>+0%M'::4<6O6AN%JFC!1FR-R,;Y^',XH"TS%E0BFB/"+<(M_>&
M;&;(HDNNX151I[6^;G&'BZM)BMF',G2*MDX;,D2'>]]PYANN,!XZK9C31A@F
MP@W7&";:(V5<3"=AZ&.8=#@$%M#P[W-.\>>D$;*S?S9=(VURED,%AJ9>^\7/
M6MMJN3J[3@UMJB5<&Z]:-:B&^Q?(@>CC"F5N9'-TU/O)