UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 6-K
Report of Foreign Private Issuer
Pursuant to Rule 13a-16 or 15d-16 under the Securities
Exchange Act of 1934
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For November 2017 |
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Commission File Number: 1-34513 |
CENOVUS ENERGY INC.
(Translation of registrants name into English)
2600, 500 Centre Street S.E.
Calgary, Alberta, Canada T2G 1A6
(Address of principal executive office)
Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F.
Form 20-F ☐ Form 40-F ☒
Indicate by check mark if the registrant is submitting the Form
6-K in paper as permitted by Regulation S-T Rule 101(b)(1):
Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7):
DOCUMENTS FILED AS PART OF THIS FORM 6-K
See the Exhibit Index to this Form 6-K.
SIGNATURES
Pursuant to the requirements
of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Date: November 8, 2017
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CENOVUS ENERGY INC. |
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(Registrant) |
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By: |
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/s/ Elizabeth A. McNamara |
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Name: |
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Elizabeth A. McNamara |
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Title: |
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Assistant Corporate Secretary |
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Form 6-K Exhibit Index
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Exhibit No. |
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99.1 |
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Interim Report to Shareholders for the period ended September 30, 2017 |
Exhibit 99.1
Cenovus reports solid third quarter results
Achieves strong adjusted funds flow accretion from acquisition
Calgary, Alberta (November 2, 2017) Cenovus Energy Inc. (TSX: CVE) (NYSE: CVE) delivered strong cash from operating activities and
adjusted funds flow in the third quarter including three full months of solid contribution from the oil sands and Deep Basin assets acquired on May 17, 2017. To further optimize its portfolio and deleverage its balance sheet, the company has
announced sale agreements for its Pelican Lake, Suffield and Palliser assets for combined gross cash proceeds of approximately $2.8 billion. Cenovus continues to target $4 billion to $5 billion of cumulative announced sale agreements
in 2017. Through a continued focus on capital discipline and strong operational performance, Cenovus generated $544 million in free funds flow in the quarter.
Key highlights
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Increased third quarter cash from operating activities and adjusted funds flow by 91% and 133% respectively, compared
with the same period in 2016 |
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Recorded a net loss of $69 million, a 73% improvement over Q3 2016 |
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Retired $950 million of the companys $3.6 billion asset-sale bridge facility |
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Reduced planned 2017 capital spending guidance by $100 million to $1.6 billion at the midpoint with no
expected impact to production in core areas. The reduced capital forecast reflects further cost and capital improvements achieved this year. |
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Financial & production summary
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(For the period ended September
30) |
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2017
Q3 |
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2016 Q3 |
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% change |
Financial1 ($ millions, except per share
amounts) |
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Cash from operating activities |
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592 |
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310 |
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91 |
Adjusted funds flow2 |
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982 |
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422 |
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133 |
Per share diluted |
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0.80 |
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0.51 |
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Free funds flow2 |
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544 |
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214 |
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154 |
Operating earnings/loss2 |
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340 |
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-236 |
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Per share diluted |
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0.28 |
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-0.28 |
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Net loss3 |
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-69 |
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-251 |
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Per share diluted |
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-0.06 |
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-0.30 |
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Capital investment |
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438 |
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208 |
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111 |
Production (before
royalties) |
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Oil sands (bbls/d) |
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362,494 |
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153,591 |
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136 |
Deep Basin liquids4 (bbls/d) |
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32,864 |
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n/a |
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n/a |
Conventional oil4,5 (bbls/d) |
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53,697 |
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54,481 |
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-1 |
Total oil and liquids (bbls/d) |
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449,055 |
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208,072 |
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116 |
Deep Basin natural gas (MMcf/d) |
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495 |
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n/a |
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n/a |
Conventional natural gas5 (MMcf/d) |
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356 |
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392 |
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-9 |
Total natural gas (MMcf/d) |
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851 |
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392 |
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117 |
Total production (BOE/d) |
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590,851 |
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273,405 |
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116 |
1 |
Financial information includes results from discontinued operations.
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Adjusted funds flow, free funds flow and operating earnings/loss are
non-GAAP measures. See Advisory. |
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Net loss includes a non-cash
after-tax loss of approximately $440 million related to the disposition of Cenovuss Pelican Lake assets. |
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Includes natural gas liquids (NGLs). |
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Majority of assets have been sold, have sale agreements in place or are being marketed and are presented as discontinued
operations. Conventional natural gas includes 6 MMcf/d of Athabasca natural gas for Q3 2017. |
Overview
In the third quarter of 2017, Cenovus continued to realize the benefits of its May 17, 2017 asset acquisition, which included taking complete
ownership of its best-in-class oil sands assets in northern Alberta and adding a new core production area in the Deep Basin in Alberta and British Columbia. With a full
quarter contribution from the acquired assets, the company increased cash from operating activities and adjusted funds flow by 91% and 133% respectively, free funds flow by 154% and total production by 116% compared with the third quarter of 2016.
Planned asset divestitures
As part of its strategy, the
company is focused on its two core production areasthe oil sands and the Deep Basin. To further optimize its portfolio, Cenovus put its legacy conventional oil and natural gas assets up for sale in the first half of 2017. The company has
successfully closed the sale of its Pelican Lake assets and used the net proceeds from the transaction to repay the first tranche and a portion of the second tranche of its $3.6 billion asset-sale bridge facility. Sale agreements have also been
announced for the Suffield and Palliser assets and, upon closing, Cenovus intends to apply the net proceeds from those transactions to further reduce the bridge facility. The company is also in the final stages of an analysis of its Deep Basin
assets with a view to identifying non-core properties for potential sale.
Im very pleased with
the progress weve made so far in streamlining our portfolio and reducing near-term leverage, which remains our top priority, said Brian Ferguson, Cenovus President & Chief Executive Officer. I believe the sale agreements
reached to date and the significant interest in our Weyburn operation showcase the quality of these assets and they give me confidence that we will deliver on our 2017 divestiture target.
CEO succession plan
Mr. Ferguson is retiring as
President & Chief Executive Officer and as a director of the company as of the end of today, November 2, 2017 and will continue in an advisory role reporting to the Board Chair until March 31, 2018 to facilitate the leadership
transition. As announced on October 30, 2017, Cenovus is pleased to introduce Alex Pourbaix as President & Chief Executive Officer beginning on November 6, 2017.
Financial performance
During the third quarter, Cenovus
generated adjusted funds flow of $982 million or $0.80 per share compared with $422 million or $0.51 per share in the same period a year earlier. This was mostly due to higher liquids and natural gas sales volumes, higher realized
liquids pricing as well as higher average benchmark crack spreads compared with 2016. The increase in adjusted funds flow was partially offset by realized foreign exchange losses on working capital, a rise in finance costs primarily associated with
additional debt incurred to finance the acquisition and higher general and administrative (G&A) costs.
Third quarter cash from operating
activities was $592 million, compared with $310 million in the same period in 2016. The companys combined upstream portfolio generated operating margin net of capital investment of $626 million in the third quarter, including a
full three months of contribution from the acquired assets. Cenovus had third quarter free funds flow of $544 million compared with $214 million in the same period of 2016. Year to date,
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Cenovus Energy Inc. Third Quarter 2017 Report |
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Cenovus has generated over $1 billion of free funds flow, even with the benchmark price of West Texas Intermediate (WTI) crude oil averaging less than US$50.00 per barrel.
Net loss was $69 million during the third quarter, compared with a loss of $251 million in the same period in 2016. The net loss includes a
non-cash after-tax loss of approximately $440 million related to the disposition of Cenovuss Pelican Lake assets. Operating earnings were $340 million in the third quarter, compared with a loss
of $236 million in the same period in 2016.
Hedging
Concurrent with its asset sale processes and to further support the companys financial resilience while the balance of the asset-sale bridge loan
remains outstanding, Cenovus has accelerated its hedging program and has hedged a greater percentage of forecast liquids and natural gas volumes. As of October 25, 2017, the company had crude oil hedges in place on 249,000 barrels per day
(bbls/d) for the remainder of this year at an average floor price of approximately US$50.72/bbl. The company also had 325,000 bbls/d hedged for the first half of 2018 with an average floor price of approximately US$50.09/bbl and 150,000 bbls/d
with an average floor price of approximately US$49.16/bbl for the second half of 2018. As of October 25, 2017 Cenovus had natural gas hedges in place at an average New York Mercantile Exchange (NYMEX) price of approximately US$3.07 per million
British thermal units per day (MMBtu/d) on 202,000 MMBtu/d for the remainder of 2017. Cenovuss 2018 hedging activity is weighted towards the first half of the year and focused on providing downside price protection. The company expects to get
back to a more normalized level of hedging subsequent to the completion of its asset sale program.
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Current hedge positions for 2017 |
Hedges at October 25,
2017 |
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Volume |
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Price |
Crude Brent
Fixed Price
October - December
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144,000 bbls/d |
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US$51.23/bbl |
Crude WTI
Collars
October - December
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50,000 bbls/d |
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US$44.84/bbl - US$56.47/bbl |
Crude Brent Put
Contracts
October - December
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55,000 bbls/d |
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US$53.00/bbl |
Crude Brent
- WTI Spread
October - December
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50,000 bbls/d |
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US$(1.88)/bbl |
Natural Gas
NYMEX Fixed Price
October - December
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~202,000 MMBtu/d |
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~US$3.07/MMBtu |
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Current hedge positions for 2018 |
Hedges at October 25,
2017 |
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Volume |
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Price |
Crude Brent
Collars
January - June
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80,000 bbls/d |
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US$49.54/bbl - US$59.86/bbl |
Crude Brent
Fixed Price
January - June
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60,000 bbls/d |
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US$53.34/bbl |
Crude Brent Put
Contracts
January - June
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25,000 bbls/d |
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US$53.00/bbl |
Crude WTI
Collars
January - June
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10,000 bbls/d |
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US$45.30/bbl - US$62.77/bbl |
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Cenovus Energy Inc. Third Quarter 2017 Report |
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Current hedge positions for 2018 |
Hedges at October 25,
2017 |
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Volume |
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Price |
Crude WTI Fixed
Price
January - June
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150,000 bbls/d |
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US$48.91/bbl |
Crude WCS
Differential
January - June
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~25,200 bbls/d |
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~US$(13.92)/bbl |
Crude WTI Fixed Price
July -
December |
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75,000 bbls/d |
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US$49.32/bbl |
Crude Brent
Collars
July - December
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75,000 bbls/d |
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US$49.00/bbl - US$59.69/bbl |
Crude WCS
Differential
July - December
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~9,600 bbls/d |
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~US$(14.48)/bbl |
Continued cost leadership & capital discipline
Since 2014, Cenovus has achieved significant cost reductions across its business, including reducing its
per-barrel oil sands non-fuel operating costs by more than 30% and its per-barrel oil sands sustaining capital costs by 50%. As
part of its continued focus on cost leadership, the company is committed to achieving an additional $1 billion of cumulative capital, operating and G&A cost reductions over the next three years.
To reflect the expected ongoing cost savings and efficiency improvements in its base business as well as the companys continued focus on capital
discipline, Cenovus has further updated its capital spending guidance for 2017. Compared with the companys July 26, 2017 guidance, total planned capital expenditures this year have been reduced by another $100 million at the
midpoint, with no expected impact to forecast production volumes for Cenovuss core areas in the oil sands and Deep Basin. The majority of the reduced capital spending forecast relates to continued improvements in drilling performance,
development planning and optimized scheduling of well start-ups at Cenovuss oil sands operations. Updated guidance is available at cenovus.com under Investors.
Cenovus plans to take a disciplined approach to capital investment for 2018, prioritizing
near-term debt reduction and increased free funds flow over production growth. The company intends to provide its 2018 budget overview later this year.
Operating highlights
Oil sands
Production at Cenovuss Christina Lake and Foster Creek oil sands operations rose to 362,494 bbls/d in the third quarter of 2017, an increase of
136% from the same period a year ago. The increase was mainly due to the acquisition and to incremental volumes from Foster Creek phase G and Christina Lake phase F, both of which began producing in the second half of 2016. Production at Foster
Creek was impacted by temporary treating issues during the month of August, which are routinely encountered with the start-up of new sustaining well pads. Volumes recovered through September and the project
continues to be on track to meet full-year production guidance.
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At Foster Creek, the steam to oil ratio (SOR), the amount of steam needed to produce one barrel of oil, was
2.5 in the third quarter of 2017, compared with 2.6 in the same period of 2016. At Christina Lake, the SOR was 1.8 in the third quarter of 2017, compared with 1.9 a year earlier.
Construction at Christina Lake phase G resumed in the first quarter of 2017, and activity has increased through the third quarter. The expansion, which
is expected to be completed with go-forward capital investment of between $16,000 and $18,000 per flowing barrel, is anticipated to begin production in the second half of 2019.
Deep Basin
Integration of the companys newly acquired
Deep Basin assets has gone according to plan and the company is pleased with the execution of its capital program to date. Production from the Deep Basin averaged 115,301 barrels of oil equivalent per day (BOE/d), in line with the companys
expectations. Cenovus continues to take a disciplined approach to development, with plans to peak at seven active rigs and drill 28 wells across the Deep Basin by year-end.
Downstream
Operating margin from refining and marketing was
$211 million in the quarter, compared with $68 million in the same period of 2016. The increase was largely the result of higher average market crack spreads, partially offset by narrower light-heavy oil differentials and the appreciating
value of the Canadian dollar. The companys refining operating margin is calculated on a first-in, first-out (FIFO) inventory accounting basis. Using the last-in, first-out (LIFO) accounting method employed by most U.S. refiners, Cenovuss operating margin from refining and marketing would have been $9 million
lower in the quarter. In the third quarter of 2016, operating margin would have been $33 million higher on a LIFO reporting basis.
Other developments
For the fourth quarter of 2017, the Board of Directors has declared a dividend of $0.05 per share, payable on December 29, 2017 to common
shareholders of record as of December 15, 2017. Based on the November 1, 2017 closing share price on the Toronto Stock Exchange of $13.01, this represents an annualized yield of about 1.5%. Declaration of dividends is at the sole
discretion of the Board and will continue to be evaluated on a quarterly basis.
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MANAGEMENTS DISCUSSION AND ANALYSIS
This Managements Discussion and
Analysis (MD&A) for Cenovus Energy Inc. (which includes references to we, our, us, its, or Cenovus, mean Cenovus Energy Inc., the subsidiaries of, and partnership interests
held by, Cenovus Energy Inc. and its subsidiaries) dated November 1, 2017, should be read in conjunction with our September 30, 2017 unaudited interim Consolidated Financial Statements and accompanying notes (interim Consolidated
Financial Statements), the December 31, 2016 audited Consolidated Financial Statements and accompanying notes (Consolidated Financial Statements) and the December 31, 2016 MD&A (annual MD&A). All of
the information and statements contained in this MD&A are made as of November 1, 2017, unless otherwise indicated. This MD&A provides an update to our annual MD&A and contains forward-looking information about our current expectations,
estimates, projections and assumptions. The information in this MD&A, as it relates to our operations for the three and nine months ended September 30, 2017, reflects the closing of the Acquisition (as defined in this MD&A) on
May 17, 2017. 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 (Management) prepared the
MD&A. The interim MD&As are approved by the Audit Committee of the Cenovus Board of Directors (the Board) and the annual MD&A is reviewed by the Audit Committee and recommended for its approval by the Board. 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, on 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 interim 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 and Additional Subtotals
Certain financial measures in this document do not have a standardized meaning as prescribed by IFRS, such as Netbacks, Adjusted Funds Flow, Operating
Earnings, Free Funds Flow, Debt, Net Debt, Capitalization and Adjusted Earnings Before Interest, Taxes, Depreciation and Amortization (Adjusted EBITDA) and therefore are considered non-GAAP
measures. In addition, Operating Margin is considered an additional subtotal found in Note 1 and Note 8 of our interim Consolidated Financial Statements. 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, if applicable, of each non-GAAP measure or additional subtotal is presented in the Financial Results, Operating Results, Liquidity and Capital Resources, or Advisory sections of this
MD&A.
OVERVIEW OF CENOVUS
We are a Canadian integrated oil company
headquartered in Calgary, Alberta, with our shares listed on the Toronto and New York stock exchanges. On September 30, 2017, we had an enterprise value of approximately $27 billion. We are in the business of developing, producing and
marketing crude oil, natural gas liquids (NGLs) and natural gas in Western Canada. We also conduct marketing activities and have refining operations in the United States (U.S.). Our average crude oil and NGLs (collectively,
liquids) production for the three months ended September 30, 2017 was 449,055 barrels per day, our average natural gas production was 851 MMcf per day, and our total reported production was 590,851 BOE per day. The refining
operations processed an average of 462,000 gross barrels per day of crude oil feedstock into an average of 490,000 gross barrels per day of refined products.
Our Strategy
On
May 17, 2017, we closed an acquisition from ConocoPhillips Company and certain of its subsidiaries (collectively, ConocoPhillips) where we acquired their 50 percent interest in FCCL Partnership (FCCL) and the
majority of ConocoPhillips western Canadian conventional assets in Alberta and British Columbia (the Acquisition). In order to finance the Acquisition, we incurred additional debt. We are focused on deleveraging our balance sheet
through the sale of our legacy Conventional crude oil and natural gas assets and generating increased Free Funds Flow.
We updated our strategy in the
second quarter of 2017 to reflect the closing of the Acquisition and our increased focus on Free Funds Flow. Our strategy is to increase cash flows through disciplined production growth from our vast portfolio of oil sands and Deep Basin natural gas
and liquids assets in Western Canada. We are focused on increasing our current share price and maximizing shareholder value through cost leadership and realizing the best margins for our products to help us maintain financial resilience and deliver
sustainable dividend growth. We plan to achieve our strategy by drawing on the expertise of our people and leveraging our strategic differentiators: premium asset quality, executional excellence, value-added integration, focused innovation and
trusted reputation.
We measure our performance through a balanced scorecard that reflects our financial, operational, safety, environmental and
organizational health goals.
Our Key Strategic Differentiators
Premium Asset Quality
Cenovus has a deep portfolio of premium-quality oil sands, conventional oil, and natural gas assets that we believe provide us with significant cost and
environmental performance advantages. Our in-situ oil sands projects and Deep Basin assets in Western Canada offer long- and short-cycle opportunities that provide the capital investment flexibility to
position us to deliver value growth at various points of the price cycle. In addition to our exploration and production assets, we have complementary interests in refineries and product transportation infrastructure.
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Cenovus Energy Inc.
Third Quarter 2017 Report |
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Page 6
Managements Discussion and Analysis |
Executional Excellence
Our team is committed to delivering on our business plan in a safe, disciplined and responsible manner and continuously improving our performance to help
manage risk and optimize returns. We use a manufacturing approach to support consistent performance and enhance reliability. This involves applying standardized and repeatable designs and processes to the construction and operation of our facilities
to reduce costs and improve efficiencies at all project stages. We strive to execute our work in an agile manner with a focus on using our resources effectively.
Value-Added Integration
Our integrated business approach helps provide stability to our cash flows and maximize value for the oil and natural gas we produce. Having ownership in
oil refineries positions us to capture the full value chain from production to high-quality end products like transportation fuels. In addition, our pipeline commitments, marine capability, crude-by-rail loading facility and product marketing activities position us to obtain global pricing for our oil. As a consumer of natural gas at our oil sands facilities and refineries, our natural gas
production acts as an economic hedge to help manage price volatility. In addition, our cogeneration plants efficiently provide power for our oil sands facilities with the added value of excess electricity being sold to the grid.
Focused Innovation
We focus our innovation efforts on accelerating the adoption of technology solutions and methods of operating to enhance safety, aggressively reduce
costs, improve margins and lower emissions. We expect innovation at Cenovus to mean significant improvements and game-changing developments that are implemented to generate value. We embrace the fail fast mentality as essential to
encouraging behaviours that can transform how we operate. The application of digital innovation across our business is expected to be a key contributor to our competitive advantage. We aim to complement our internal technology development efforts
with external collaboration that brings together smart people with diverse ideas that leverage our technology spend.
Trusted
Reputation
We are a responsible, progressive company that is committed to providing a safe and healthy workplace, building strong external
relationships, minimizing our environmental footprint and being a part of a zero-emissions future. Our actions are intended to support our trusted reputation and enable us to attract and retain top-quality staff and to engage with and be respected by our stakeholders: investors, the communities in which we operate, environmental groups, governments, Aboriginal people, media, project partners and the
general public.
Our Operations
Oil Sands
Our oil sands assets include steam-assisted gravity drainage (SAGD) oil sands projects in northern Alberta, including Foster Creek, Christina
Lake, Narrows Lake and other emerging projects. Foster Creek and Christina Lake are producing, while Narrows Lake is in the initial stages of development. These three projects, located in the Athabasca region of northeastern Alberta, are
100 percent owned by Cenovus following the Acquisition. Our 100 percent-owned emerging project at Telephone Lake is located within the Borealis region of northeastern Alberta. 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.
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Nine Months Ended
September 30, 2017 |
($ millions) |
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Crude Oil |
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Natural Gas |
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Operating Margin |
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1,612 |
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3 |
Capital Investment |
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654 |
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6 |
Operating Margin Net of Related Capital Investment |
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958 |
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(3) |
Deep Basin
The Deep Basin includes approximately three million net acres of land rich in natural gas, condensate and other NGLs, and light and medium oil. The assets
are located primarily in the Elmworth-Wapiti, Kaybob-Edson, and Clearwater operating areas and include interests in numerous natural gas processing facilities (collectively, the Deep Basin Assets). The Deep Basin Assets are expected to
provide short-cycle development opportunities with high return potential that complement our long-term oil sands development and provide an economic hedge for the natural gas required as a fuel source at both our oil sands and refining operations.
The Deep Basin Assets were acquired on May 17, 2017.
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($ millions) |
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May 17
September 30,
2017 |
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Operating Margin |
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119 |
Capital Investment |
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77 |
Operating Margin Net of Related Capital Investment |
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42 |
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Cenovus Energy Inc.
Third Quarter 2017 Report |
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Page 7
Managements Discussion and Analysis |
Conventional
Our Conventional segment has been classified as a discontinued operation. We are currently marketing for sale or have sales agreements in place for the
remaining assets within our Conventional segment. In the third quarter, we sold our Pelican Lake heavy oil assets, including the adjacent Grand Rapids project, for gross cash proceeds of $975 million. We also announced the divestiture of our
Suffield crude oil and natural gas assets for gross cash proceeds of $512 million. The sale is expected to close in the fourth quarter of 2017, subject to customary closing conditions.
On October 19, 2017, we announced the divestiture of our Palliser crude oil and natural gas operations in southern Alberta for gross cash proceeds of
$1.3 billion. The sale of the Palliser assets is expected to close in the fourth quarter of 2017, subject to customary closing conditions.
Crude
oil production from our Conventional business segment generates dependable near-term cash flows while the natural gas production acts as an economic hedge for the natural gas required as a fuel source at both our oil sands and refining operations.
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Nine Months Ended
September 30, 2017 |
($ millions) |
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Liquids |
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Natural Gas |
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Operating Margin |
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310 |
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109 |
Capital Investment |
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173 |
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7 |
Operating Margin Net of Related Capital Investment |
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137 |
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102 |
Refining and Marketing
Our operations include two refineries located in Illinois and Texas that are jointly owned with (50 percent interest) and operated by
Phillips 66, an unrelated U.S. public company. The gross crude oil capacity at the Wood River and Borger refineries (the Refineries) is approximately 314,000 barrels per day and 146,000 barrels per day, respectively. This includes
processing capability of up to 255,000 gross barrels per day of blended heavy crude oil. The 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 light/heavy 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) |
|
Nine Months
Ended
September 30, 2017 |
Operating Margin |
|
284 |
Capital Investment |
|
124 |
Operating Margin Net of Related Capital Investment |
|
160 |
FINANCING THE ACQUISITION
On May 17, 2017, we closed the
Acquisition which provided us with control over our oil sands operations, doubled our oil sands production, and almost doubled our proved bitumen reserves. In addition, the Deep Basin Assets provide a second core operating area with more than three
million net acres of land, exploration and production assets, and related infrastructure in Alberta and British Columbia. The Deep Basin Assets are expected to provide complementary short-cycle development opportunities with high-return potential.
The safe and efficient integration of the Deep Basin Assets is on track and continues to be
a top priority for Cenovus. We are committed to ensuring responsible operations as we establish ourselves as a new operator in the Deep Basin area.
To finance the Acquisition, we:
|
· |
|
Completed an offering for US$2.9 billion of senior unsecured notes; |
|
· |
|
Borrowed $3.6 billion under a committed asset sale bridge credit facility (Bridge Facility);
|
|
· |
|
Completed a Bought-Deal Common Share Offering for 187.5 million common shares, raising gross proceeds of
$3.0 billion; |
|
· |
|
Issued 208 million common shares as part of the consideration paid to ConocoPhillips; and |
|
· |
|
Funded the remainder of the purchase price with cash on hand and a draw on our existing committed credit facility.
|
The financing, which increased the leverage on our balance sheet, was executed according to plan and supported by three investment
grade credit ratings. The increase in leverage is expected to be temporary as we are selling
|
|
|
Cenovus Energy Inc.
Third Quarter 2017 Report |
|
Page 8
Managements Discussion and Analysis |
our legacy Conventional crude oil and natural gas assets in order to deleverage our balance sheet. We have completed the first of a series of anticipated divestitures, namely our Pelican Lake
assets and the adjacent Grand Rapids project, for gross cash proceeds of $975 million. Net cash proceeds from the sale have been applied against the $3.6 billion committed Bridge Facility.
On September 25, 2017, we announced the sale of our Suffield crude oil and natural gas operations in southern Alberta for gross cash proceeds of
$512 million, plus a deferred purchase price adjustment (DPPA). The sale includes our crude oil and natural gas assets located on the Canadian Forces Base Suffield and the adjacent Alderson property (collectively, the Suffield
Divestiture). The DPPA is a two-year agreement that begins on January 1, 2018, with maximum combined purchase price adjustments of $36 million if average crude oil and natural gas prices rise
over the next two years. We are entitled to receive cash for each month in which the average daily price of WTI is above US$55 per barrel or the price of Henry Hub natural gas is above US$3.50 per MMBtu. The Suffield Divestiture is expected to close
in the fourth quarter, subject to customary closing conditions.
On October 19, 2017, we announced the divestiture of our Palliser crude oil and
natural gas operations in southern Alberta for gross cash proceeds of $1.3 billion. The sale includes our crude oil and natural gas assets in the areas near Drumheller, Brooks and Langevin (collectively, the Palliser Divestiture).
The sale of the Palliser assets is expected to close in the fourth quarter of 2017, subject to closing conditions. The divestiture process for our remaining legacy Conventional assets, notably our
CO2 enhanced oil recovery project at Weyburn, in southern Saskatchewan, is proceeding well.
Additional information on the Acquisition is available in our June 30, 2017 MD&A and our news release dated March 29, 2017 available on
SEDAR at sedar.com, on EDGAR at sec.gov, and on our website at cenovus.com; in our material change report dated April 5, 2017 and in our Business Acquisition Report dated July 19, 2017, both available on SEDAR and EDGAR.
QUARTERLY HIGHLIGHTS
We have completed key steps in the plan to
deleverage our balance sheet with the announcement of three divestitures, closing one of them. Gross proceeds from these divestitures will total approximately $2.8 billion.
We generated Free Funds Flow of $544 million in the quarter, a significant increase from $214 million in the third quarter of 2016, primarily
due to the Acquisition.
Production increased significantly in the quarter to 590,851 BOE per day in 2017 (2016 273,405 BOE per day) primarily
related to the Acquisition. Incremental production from the Acquisition was 296,549 BOE per day for the three months ended September 30, 2017.
Crude oil prices continued to be volatile in the quarter. WTI ranged from a high of US$52.22 per barrel to a low of US$44.23 per barrel and averaged seven
percent higher compared with 2016. In addition, AECO was very volatile, ranging from a high of $2.71 per Mcf to a low of $1.24 Mcf and averaging seven percent lower than the third quarter of 2016. Our average sales price rose 12 percent from
2016, contributing to a companywide Netback of $18.40 per BOE in the third quarter, before realized hedging. We continue to focus on cost leadership and capital discipline to help maintain financial resilience, while delivering safe and reliable
operations.
In the third quarter, we:
· |
|
More than doubled our total liquids production compared with the third quarter of 2016, primarily due to incremental
production volumes from the Acquisition and our oil sands expansion phases; |
· |
|
Generated combined upstream revenues, including the Conventional segment, of $2,629 million compared with
$1,084 million in 2016, primarily related to a rise in sales volumes and higher liquids sales prices; |
· |
|
Reported upstream operating costs, including the Conventional segment, of $476 million, an increase of
$246 million compared with the third quarter of 2016 primarily due to the Acquisition; |
· |
|
Achieved Cash From Operating Activities and Adjusted Funds Flow of $592 million and $982 million, respectively,
increasing significantly from the third quarter of 2016; |
· |
|
Recorded Net Earnings From Continuing Operations of $288 million (2016 Net Loss From Continuing Operations of
$55 million); |
· |
|
Invested $438 million in capital which allowed us to generate Free Funds Flow of $544 million in the quarter;
|
· |
|
Sold our Pelican Lake assets and the adjacent Grand Rapids project on September 29, 2017 for gross cash proceeds of
$975 million and repaid the first tranche and a portion of the second tranche of our committed Bridge Facility; and |
· |
|
Announced the Suffield Divestiture. The sale is expected to close in the fourth quarter, subject to customary closing
conditions, generating gross cash proceeds of $512 million, plus a DPPA. |
In October, we announced the Palliser Divestiture.
The sale is expected to close in the fourth quarter, subject to customary closing conditions, generating gross cash proceeds of $1.3 billion.
|
|
|
Cenovus Energy Inc.
Third Quarter 2017 Report |
|
Page 9
Managements Discussion and Analysis |
OPERATING RESULTS
Our upstream assets continued to perform well
in the three and nine months ended September 30, 2017. Total production increased primarily due to the Acquisition.
Production Volumes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
Nine Months Ended September 30, |
|
|
2017 |
|
|
|
Percent
Change |
|
|
|
2016 |
|
|
|
2017 |
|
|
|
Percent
Change |
|
|
|
2016 |
|
|
|
|
|
|
|
|
|
|
|
|
Liquids (barrels per day) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil Sands |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foster Creek |
|
154,363 |
|
|
|
109% |
|
|
|
73,798 |
|
|
|
114,632 |
|
|
|
73% |
|
|
|
66,435 |
Christina Lake |
|
208,131 |
|
|
|
161% |
|
|
|
79,793 |
|
|
|
154,634 |
|
|
|
97% |
|
|
|
78,321 |
|
|
362,494 |
|
|
|
136% |
|
|
|
153,591 |
|
|
|
269,266 |
|
|
|
86% |
|
|
|
144,756 |
Deep Basin |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Light and Medium Oil |
|
6,494 |
|
|
|
-% |
|
|
|
- |
|
|
|
3,208 |
|
|
|
-% |
|
|
|
- |
NGLs |
|
26,370 |
|
|
|
-% |
|
|
|
- |
|
|
|
13,498 |
|
|
|
-% |
|
|
|
- |
|
|
32,864 |
|
|
|
-% |
|
|
|
- |
|
|
|
16,706 |
|
|
|
-% |
|
|
|
- |
Conventional (Discontinued Operations) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Heavy Oil |
|
25,549 |
|
|
|
(9)% |
|
|
|
28,096 |
|
|
|
26,466 |
|
|
|
(10)% |
|
|
|
29,276 |
Light and Medium Oil |
|
26,947 |
|
|
|
6% |
|
|
|
25,311 |
|
|
|
26,430 |
|
|
|
1% |
|
|
|
26,200 |
NGLs |
|
1,201 |
|
|
|
12% |
|
|
|
1,074 |
|
|
|
1,128 |
|
|
|
10% |
|
|
|
1,027 |
|
|
53,697 |
|
|
|
(1)% |
|
|
|
54,481 |
|
|
|
54,024 |
|
|
|
(4)% |
|
|
|
56,503 |
Total Liquids Production (barrels per day) |
|
449,055 |
|
|
|
116% |
|
|
|
208,072 |
|
|
|
339,996 |
|
|
|
69% |
|
|
|
201,259 |
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas (MMcf per day) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil Sands |
|
6 |
|
|
|
(67)% |
|
|
|
18 |
|
|
|
11 |
|
|
|
(35)% |
|
|
|
17 |
Deep Basin |
|
495 |
|
|
|
-% |
|
|
|
- |
|
|
|
251 |
|
|
|
-% |
|
|
|
- |
Conventional (Discontinued Operations) |
|
350 |
|
|
|
(6)% |
|
|
|
374 |
|
|
|
351 |
|
|
|
(8)% |
|
|
|
382 |
Total Natural Gas Production (MMcf per day) |
|
851 |
|
|
|
117% |
|
|
|
392 |
|
|
|
613 |
|
|
|
54% |
|
|
|
399 |
|
|
|
|
|
|
|
|
|
|
|
|
Total Production (BOE per day) |
|
590,851 |
|
|
|
116% |
|
|
|
273,405 |
|
|
|
442,143 |
|
|
|
65% |
|
|
|
267,759 |
The increase in production at Foster Creek and Christina Lake from May 17, 2017, the closing date of the Acquisition,
until September 30, 2017 was 76,127 barrels per day and 104,985 barrels per day, respectively.
Production at Foster Creek increased in the third
quarter and on a year-to-date basis compared with 2016 due to the Acquisition and incremental production volumes from the phase G expansion, partially offset by reduced
volumes as a result of temporary treating issues in the third quarter. On a year-to-date basis, production at Foster Creek was also impacted by approximately 3,690
barrels per day due to a planned turnaround completed in the second quarter of 2017. Production at Christina Lake increased in the three and nine months ended September 30, 2017 compared to the same periods in 2016 due to the Acquisition
and incremental production volumes from the phase F expansion.
Total liquids production in the Deep Basin for the 137 day period following the
Acquisition averaged 33,290 barrels per day.
Our Conventional liquids production decreased in the third quarter and on a year-to-date basis compared with 2016 primarily due to expected natural declines, partially offset by an increase in production associated with the tight oil drilling program
in southern Alberta. We wound down our drilling program early in the third quarter due to the pending sale of these assets.
In the third quarter and
on a year-to-date basis, our natural gas production rose compared with 2016 due to the Acquisition, partially offset by expected natural declines in our Conventional
segment. Natural gas production from the Deep Basin for the 137 days of operations in 2017 was 500 MMcf per day.
Netbacks
Netback is a non-GAAP measure commonly used in the oil and gas industry to assist in measuring operating
performance on a per-unit basis. Netbacks reflect our margin on a per-barrel of oil equivalent basis. Netback is defined as gross sales less royalties, transportation
and blending, operating expenses, and production and mineral taxes divided by sales volumes. Netbacks do not reflect the non-cash write-downs of product inventory until the product is sold. The sales price,
transportation and blending costs, and sales volumes exclude the impact of
|
|
|
Cenovus Energy Inc.
Third Quarter 2017 Report |
|
Page 10
Managements Discussion and Analysis |
purchased condensate. Condensate is blended with the heavy oil to reduce its thickness in order to transport it to market. Our Netback calculation is aligned with the definition found in the
Canadian Oil and Gas Evaluation Handbook. For a reconciliation of our Netbacks see the Advisory section of this MD&A.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
September 30, |
|
Nine Months Ended
September 30, |
($/BOE) |
|
2017 |
|
|
|
2016 |
|
|
|
2017 |
|
|
|
2016 |
|
|
|
|
|
|
|
|
Sales Price |
|
33.71 |
|
|
|
29.98 |
|
|
|
34.89 |
|
|
|
24.37 |
Royalties |
|
2.08 |
|
|
|
1.55 |
|
|
|
2.37 |
|
|
|
1.29 |
Transportation and Blending |
|
4.56 |
|
|
|
4.51 |
|
|
|
4.56 |
|
|
|
4.69 |
Operating Expenses |
|
8.59 |
|
|
|
8.92 |
|
|
|
9.18 |
|
|
|
9.32 |
Production and Mineral Taxes |
|
0.08 |
|
|
|
0.15 |
|
|
|
0.12 |
|
|
|
0.12 |
Netback Excluding Realized Risk Management
(1) |
|
18.40 |
|
|
|
14.85 |
|
|
|
18.66 |
|
|
|
8.95 |
Realized Risk Management Gain (Loss) |
|
(0.24) |
|
|
|
1.63 |
|
|
|
(0.77) |
|
|
|
3.05 |
Netback Including Realized Risk Management
(1) |
|
18.16 |
|
|
|
16.48 |
|
|
|
17.89 |
|
|
|
12.00 |
(1) |
Includes results from our Conventional segment, which has been classified as a discontinued operation. |
The rise in our average Netback was primarily due to higher liquids sales prices, partially offset by a rise in royalties and the strengthening of the
Canadian dollar relative to the U.S. dollar. In the third quarter of 2017, our average Netback rose despite a decline in natural gas prices. On a year-to-date basis, the
strengthening of the Canadian dollar compared with 2016 had a negative impact on our sales price of approximately $0.40 per BOE.
Refining
In the
third quarter, refined product output declined compared with 2016 primarily due to unplanned maintenance at both Refineries in 2017. In addition, lower heavy crude oil volumes were processed due to optimization of the total crude input slate to
address narrowing heavy crude oil differentials.
On a year-to-date
basis, crude oil runs and refined product output decreased due to the larger scope of the planned turnarounds at both Refineries during the first quarter of 2017 compared with 2016, in addition to unplanned maintenance at both Refineries in 2017.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
Nine Months Ended September 30, |
|
|
2017 |
|
|
|
Percent
Change |
|
|
|
2016 |
|
|
|
2017 |
|
|
|
Percent
Change |
|
|
|
2016 |
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil Runs (1)
(Mbbls/d) |
|
462 |
|
|
|
-% |
|
|
|
463 |
|
|
|
439 |
|
|
|
(3)% |
|
|
|
452 |
Heavy Crude Oil (1) |
|
213 |
|
|
|
(12)% |
|
|
|
241 |
|
|
|
205 |
|
|
|
(14)% |
|
|
|
237 |
Refined Product (1)
(Mbbls/d) |
|
490 |
|
|
|
(1)% |
|
|
|
494 |
|
|
|
467 |
|
|
|
(3)% |
|
|
|
479 |
Crude Utilization
(1) (percent) |
|
100 |
|
|
|
(1)% |
|
|
|
101 |
|
|
|
95 |
|
|
|
(3)% |
|
|
|
98 |
(1) |
Represents 100 percent of the Wood River and Borger refinery operations. |
Operating Margin
from Refining and Marketing in the three and nine months ended September 30, 2017 was $211 million and $284 million, respectively (2016 $68 million and $238 million, respectively). The increases were primarily due to
higher average market crack spreads, partially offset by narrowing heavy crude oil differentials.
Further information on the changes in our
production volumes, items included in our Netbacks and refining results can be found in the Reportable Segments section of this MD&A. Further information on our risk management activities can be found in the Risk Management section of this
MD&A and in the notes to the interim Consolidated Financial Statements.
COMMODITY PRICES UNDERLYING OUR FINANCIAL RESULTS
Key performance drivers for our
financial results include commodity prices, price differentials, refining crack spreads as well as the U.S./Canadian dollar exchange rate. The following table shows selected market benchmark prices and the U.S./Canadian dollar average exchange rates
to assist in understanding our financial results.
|
|
|
Cenovus Energy Inc.
Third Quarter 2017 Report |
|
Page 11
Managements Discussion and Analysis |
Selected Benchmark Prices and Exchange Rates (1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, |
|
|
|
|
|
|
|
|
|
|
|
|
(US$/bbl, unless otherwise indicated) |
|
2017 |
|
|
|
2016 |
|
|
|
Percent
Change |
|
|
|
Q3
2017 |
|
|
|
Q2
2017 |
|
|
|
Q3
2016 |
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil Prices |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Brent |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average |
|
52.59 |
|
|
|
43.01 |
|
|
|
22% |
|
|
|
52.18 |
|
|
|
50.92 |
|
|
|
46.98 |
End of Period |
|
57.54 |
|
|
|
49.06 |
|
|
|
17% |
|
|
|
57.54 |
|
|
|
47.92 |
|
|
|
49.06 |
WTI |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average |
|
49.47 |
|
|
|
41.33 |
|
|
|
20% |
|
|
|
48.21 |
|
|
|
48.29 |
|
|
|
44.94 |
End of Period |
|
51.67 |
|
|
|
48.24 |
|
|
|
7% |
|
|
|
51.67 |
|
|
|
46.04 |
|
|
|
48.24 |
Average Differential Brent-WTI |
|
3.12 |
|
|
|
1.68 |
|
|
|
86% |
|
|
|
3.97 |
|
|
|
2.63 |
|
|
|
2.04 |
WCS |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average |
|
37.59 |
|
|
|
27.65 |
|
|
|
36% |
|
|
|
38.27 |
|
|
|
37.16 |
|
|
|
31.44 |
Average (C$/bbl) |
|
49.07 |
|
|
|
36.53 |
|
|
|
34% |
|
|
|
47.96 |
|
|
|
49.95 |
|
|
|
41.04 |
End of Period |
|
40.71 |
|
|
|
34.97 |
|
|
|
16% |
|
|
|
40.71 |
|
|
|
36.36 |
|
|
|
34.97 |
Average Differential WTI-WCS |
|
11.88 |
|
|
|
13.68 |
|
|
|
(13)% |
|
|
|
9.94 |
|
|
|
11.13 |
|
|
|
13.50 |
Condensate (C5 @ Edmonton) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average (2) |
|
49.44 |
|
|
|
40.51 |
|
|
|
22% |
|
|
|
47.61 |
|
|
|
48.44 |
|
|
|
43.07 |
Average Differential WTI-Condensate (Premium)/Discount |
|
0.03 |
|
|
|
0.82 |
|
|
|
(96)% |
|
|
|
0.60 |
|
|
|
(0.15) |
|
|
|
1.87 |
Average Differential WCS-Condensate (Premium)/Discount |
|
(11.85) |
|
|
|
(12.86) |
|
|
|
(8)% |
|
|
|
(9.34) |
|
|
|
(11.28) |
|
|
|
(11.63) |
Mixed Sweet Blend (MSW @ Edmonton) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average (3) |
|
46.57 |
|
|
|
38.09 |
|
|
|
22% |
|
|
|
45.32 |
|
|
|
46.03 |
|
|
|
41.99 |
End of Period |
|
49.76 |
|
|
|
45.92 |
|
|
|
8% |
|
|
|
49.76 |
|
|
|
43.66 |
|
|
|
45.92 |
Average Refined Product Prices |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Chicago Regular Unleaded Gasoline (RUL) |
|
64.48 |
|
|
|
55.17 |
|
|
|
17% |
|
|
|
66.87 |
|
|
|
63.44 |
|
|
|
59.27 |
Chicago Ultra-low Sulphur Diesel (ULSD) |
|
65.26 |
|
|
|
54.60 |
|
|
|
20% |
|
|
|
69.73 |
|
|
|
62.18 |
|
|
|
59.86 |
Refining Margin: Average
3-2-1 Crack Spreads (4) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Chicago |
|
15.33 |
|
|
|
13.77 |
|
|
|
11% |
|
|
|
19.66 |
|
|
|
14.78 |
|
|
|
14.58 |
Average Natural Gas Prices |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
AECO (C$/Mcf) |
|
2.58 |
|
|
|
1.85 |
|
|
|
39% |
|
|
|
2.04 |
|
|
|
2.77 |
|
|
|
2.20 |
NYMEX (US$/Mcf) |
|
3.17 |
|
|
|
2.29 |
|
|
|
38% |
|
|
|
3.00 |
|
|
|
3.18 |
|
|
|
2.81 |
Basis Differential NYMEX-AECO (US$/Mcf) |
|
1.21 |
|
|
|
0.89 |
|
|
|
36% |
|
|
|
1.39 |
|
|
|
1.13 |
|
|
|
1.13 |
Foreign Exchange Rate (US$ per C$1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average |
|
0.766 |
|
|
|
0.757 |
|
|
|
1% |
|
|
|
0.798 |
|
|
|
0.744 |
|
|
|
0.766 |
(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 Netbacks table in the Operating Results section of this MD&A. |
(2) |
The average Canadian dollar condensate benchmark price for the third quarter of 2017 was $59.66 per barrel (2016
$56.23 per barrel) and for the nine months ended September 30, 2017 was $64.54 per barrel (2016 $53.51 per barrel). |
(3) |
The average Canadian dollar MSW benchmark price for the third quarter of 2017 was $56.79 per barrel (2016
$54.82 per barrel) and for the nine months ended September 30, 2017 was $60.80 per barrel (2016 $50.32 per barrel). |
(4) |
The average 3-2-1 Crack Spread is an
indicator of the refining margin and is valued on a last in, first out accounting basis. |
Crude Oil
Benchmarks
The average Brent, WTI and Western Canadian Select (WCS) benchmark prices improved in the nine months ended
September 30, 2017 compared with 2016. Compliance with the production cuts outlined in the fourth quarter of 2016 by the Organization of Petroleum Exporting Countries (OPEC) led to wide-spread market expectations of an accelerated
return to normal inventory levels. However, without supporting supply and demand drivers, prices continued to be volatile as growing supply from the U.S., unstable supply from Libya and Nigeria, severe weather related incidents, and strong global
demand resulted in varying expectations on the pace of crude oil and refined product inventory draws.
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. WTI benchmark prices weakened relative to Brent compared with the
third quarter of 2016 and on a year-to-date basis due to growing U.S. crude oil supply. In the third quarter of 2017, severe weather related incidents and strong global
demand resulted in declines to crude oil and refined product inventory levels.
WCS is blended heavy oil which consists of both conventional heavy oil
and unconventional diluted bitumen. The average WTI-WCS differential narrowed in the third quarter and on a year-to-date basis
compared with 2016. WCS strengthened relative to WTI due to a decrease in supply of blended heavy oil as a result of temporary upgrading outages related to a processing facility fire in Alberta. In addition, WCS increased due to higher demand as a
result of OPECs compliance with production cuts and lower supply from Mexico and Colombia.
|
|
|
Cenovus Energy Inc.
Third Quarter 2017 Report |
|
Page 12
Managements Discussion and Analysis |
|
|
|
WTI Benchmark Price |
|
WCS Benchmark Price |
|
|
|
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 cost attributed to transporting
the condensate to Edmonton.
The average WTI-Condensate differential narrowed in the third quarter and on a year-to-date basis compared to 2016 as a result of lower spare capacity on pipelines which increased the cost of transporting condensate to Edmonton.
MSW is an Alberta based light sweet crude oil benchmark that is representative of Canadian conventional production, comparable to the crude oil produced
by our Deep Basin Assets. The average MSW benchmark price declined in the third quarter of 2017 compared with the second quarter as a result of synthetic crude oil supply returning to the market after temporary upgrading outages related to a
processing facility fire in the second quarter of 2017.
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 refined product prices increased in the third quarter of 2017 and on a
year-to-date basis primarily due to strong refined product demand and severe weather related events that impacted the refined product output of U.S. Gulf Coast
refineries. Average Chicago 3-2-1 crack spreads rose in the three and nine months ended September 30, 2017 compared with 2016 due to the wider Brent-WTI differential, a decline in refined product supplied from the U.S. Gulf Coast, and strong refined product demand. Our realized crack spreads are affected by many other factors such as the variety of crude
oil feedstock, 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.
|
|
|
RUL Refined Product Price |
|
Chicago 3-2-1 Crack Spread |
|
|
|
Natural Gas Benchmarks
Average AECO prices in the third quarter decreased compared with 2016 primarily due to higher natural gas supply in Alberta resulting from extensive
pipeline and compressor station maintenance decreasing deliverability to storage facilities and reducing export capability. Average NYMEX natural gas prices increased in 2017 compared with the third quarter of 2016 due to lower levels of natural gas
in storage.
|
|
|
Cenovus Energy Inc.
Third Quarter 2017 Report |
|
Page 13
Managements Discussion and Analysis |
On a year-to-date basis,
average AECO and NYMEX natural gas prices rose significantly compared with 2016. Natural gas prices strengthened as North American inventory levels declined due to lower production and stronger demand. Production decreased as a result of reduced
drilling programs while demand increased from additional capacity to export North American natural gas to foreign markets, partially offset by mild weather and less natural gas used for domestic electricity generation. In addition, natural gas
prices in 2016 were negatively impacted by an exceptionally warm winter that resulted in poor heating demand and record-high seasonal North American natural gas storage levels.
Foreign Exchange Benchmark
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. An increase in the value of the Canadian dollar compared with the U.S. dollar has a negative impact on our reported results. Likewise, as the Canadian dollar weakens, our reported results are higher. In addition to our
revenues being denominated in U.S. dollars, a significant portion of our long-term debt is also U.S. dollar denominated. In periods of a strengthening Canadian dollar, our U.S. dollar debt gives rise to unrealized foreign exchange gains when
translated to Canadian dollars.
In the third quarter and on a
year-to-date basis, the Canadian dollar strengthened relative to the U.S. dollar due to strengthening of the Canadian economy, increases in the Bank of Canada benchmark
lending rate and higher commodity prices. The strengthening of the Canadian dollar in the nine months ended September 30, 2017, compared with 2016, had a negative impact of approximately $155 million on our revenues, including our
Conventional segment. As at September 30, 2017, the Canadian dollar was stronger relative to the U.S. dollar on December 31, 2016, which resulted in $715 million of unrealized foreign exchange gains on the translation of our U.S.
dollar debt.
FINANCIAL RESULTS
Selected Consolidated
Financial Results
In the three and nine months ended September 30, 2017, the Acquisition and improvements in commodity prices were
the primary drivers of our financial results. The following key performance measures are discussed in more detail within this MD&A.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
($ millions, except per share |
|
Nine Months
Ended September 30, |
|
|
2017 |
|
|
2016 |
|
|
2015 |
|
amounts) |
|
2017 |
|
|
2016 |
|
|
Q3 |
|
|
Q2 |
|
|
Q1 |
|
|
Q4 |
|
|
Q3 |
|
|
Q2 |
|
|
Q1 |
|
|
Q4 |
|
|
Q3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues (1) |
|
|
11,964 |
|
|
|
7,682 |
|
|
|
4,386 |
|
|
|
4,037 |
|
|
|
3,541 |
|
|
|
3,324 |
|
|
|
2,945 |
|
|
|
2,746 |
|
|
|
1,991 |
|
|
|
2,601 |
|
|
|
2,905 |
|
Operating Margin (2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Operating Margin |
|
|
2,444 |
|
|
|
1,172 |
|
|
|
1,216 |
|
|
|
778 |
|
|
|
450 |
|
|
|
595 |
|
|
|
487 |
|
|
|
541 |
|
|
|
144 |
|
|
|
357 |
|
|
|
602 |
|
From Continuing Operations |
|
|
2,023 |
|
|
|
781 |
|
|
|
1,099 |
|
|
|
619 |
|
|
|
305 |
|
|
|
442 |
|
|
|
335 |
|
|
|
424 |
|
|
|
22 |
|
|
|
153 |
|
|
|
360 |
|
Cash From Operating Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Cash From Operating Activities |
|
|
2,159 |
|
|
|
697 |
|
|
|
592 |
|
|
|
1,239 |
|
|
|
328 |
|
|
|
164 |
|
|
|
310 |
|
|
|
205 |
|
|
|
182 |
|
|
|
322 |
|
|
|
542 |
|
From Continuing Operations |
|
|
1,778 |
|
|
|
404 |
|
|
|
481 |
|
|
|
1,102 |
|
|
|
195 |
|
|
|
22 |
|
|
|
189 |
|
|
|
121 |
|
|
|
94 |
|
|
|
123 |
|
|
|
366 |
|
Adjusted Funds Flow (3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Adjusted Funds Flow |
|
|
2,097 |
|
|
|
888 |
|
|
|
982 |
|
|
|
792 |
|
|
|
323 |
|
|
|
535 |
|
|
|
422 |
|
|
|
440 |
|
|
|
26 |
|
|
|
275 |
|
|
|
444 |
|
From Continuing Operations |
|
|
1,700 |
|
|
|
583 |
|
|
|
867 |
|
|
|
650 |
|
|
|
183 |
|
|
|
382 |
|
|
|
296 |
|
|
|
352 |
|
|
|
(65) |
|
|
|
71 |
|
|
|
266 |
|
Operating Earnings (Loss) (3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Operating Earnings (Loss) |
|
|
699 |
|
|
|
(698) |
|
|
|
340 |
|
|
|
398 |
|
|
|
(39) |
|
|
|
321 |
|
|
|
(236) |
|
|
|
(39) |
|
|
|
(423) |
|
|
|
(438) |
|
|
|
(28) |
|
Per Share Diluted ($) |
|
|
0.66 |
|
|
|
(0.84) |
|
|
|
0.28 |
|
|
|
0.36 |
|
|
|
(0.05) |
|
|
|
0.39 |
|
|
|
(0.28) |
|
|
|
(0.05) |
|
|
|
(0.51) |
|
|
|
(0.53) |
|
|
|
(0.03) |
|
From Continuing Operations |
|
|
558 |
|
|
|
(312) |
|
|
|
253 |
|
|
|
344 |
|
|
|
(39) |
|
|
|
21 |
|
|
|
(40) |
|
|
|
(3) |
|
|
|
(269) |
|
|
|
(245) |
|
|
|
(23) |
|
Per Share Diluted ($) |
|
|
0.53 |
|
|
|
(0.37) |
|
|
|
0.21 |
|
|
|
0.31 |
|
|
|
(0.05) |
|
|
|
0.03 |
|
|
|
(0.05) |
|
|
|
- |
|
|
|
(0.32) |
|
|
|
(0.29) |
|
|
|
(0.03) |
|
Net Earnings (Loss) From Continuing Operations |
|
|
3,080 |
|
|
|
(250) |
|
|
|
288 |
|
|
|
2,581 |
|
|
|
211 |
|
|
|
(209) |
|
|
|
(55) |
|
|
|
(231) |
|
|
|
36 |
|
|
|
(448) |
|
|
|
1,806 |
|
Per Share Basic and
Diluted ($) |
|
|
2.91 |
|
|
|
(0.30) |
|
|
|
0.23 |
|
|
|
2.32 |
|
|
|
0.25 |
|
|
|
(0.25) |
|
|
|
(0.07) |
|
|
|
(0.28) |
|
|
|
0.04 |
|
|
|
(0.54) |
|
|
|
2.17 |
|
Net Earnings (Loss) |
|
|
2,782 |
|
|
|
(636) |
|
|
|
(69) |
|
|
|
2,640 |
|
|
|
211 |
|
|
|
91 |
|
|
|
(251) |
|
|
|
(267) |
|
|
|
(118) |
|
|
|
(641) |
|
|
|
1,801 |
|
Per Share Basic and
Diluted ($) |
|
|
2.62 |
|
|
|
(0.76) |
|
|
|
(0.06) |
|
|
|
2.37 |
|
|
|
0.25 |
|
|
|
0.11 |
|
|
|
(0.30) |
|
|
|
(0.32) |
|
|
|
(0.14) |
|
|
|
(0.77) |
|
|
|
2.16 |
|
Capital Investment (4) |
|
|
1,078 |
|
|
|
767 |
|
|
|
438 |
|
|
|
327 |
|
|
|
313 |
|
|
|
259 |
|
|
|
208 |
|
|
|
236 |
|
|
|
323 |
|
|
|
428 |
|
|
|
400 |
|
Free Funds Flow (3) |
|
|
1,019 |
|
|
|
121 |
|
|
|
544 |
|
|
|
465 |
|
|
|
10 |
|
|
|
276 |
|
|
|
214 |
|
|
|
204 |
|
|
|
(297) |
|
|
|
(153) |
|
|
|
44 |
|
Dividends |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Dividends |
|
|
164 |
|
|
|
124 |
|
|
|
62 |
|
|
|
61 |
|
|
|
41 |
|
|
|
42 |
|
|
|
41 |
|
|
|
42 |
|
|
|
41 |
|
|
|
132 |
|
|
|
133 |
|
Per Share ($) |
|
|
0.15 |
|
|
|
0.15 |
|
|
|
0.05 |
|
|
|
0.05 |
|
|
|
0.05 |
|
|
|
0.05 |
|
|
|
0.05 |
|
|
|
0.05 |
|
|
|
0.05 |
|
|
|
0.16 |
|
|
|
0.16 |
|
(1) |
Excludes revenues from discontinued operations. For the three and nine months ended September 30, 2017, revenues
related to discontinued operations were $286 million and $946 million, respectively (2016 $295 million and $810 million, respectively). |
(2) |
Additional subtotal found in Note 1 and Note 8 of the interim Consolidated Financial Statements and defined in this
MD&A. |
(3) |
Non-GAAP measure defined in this MD&A. |
(4) |
Includes expenditures on Property, Plant and Equipment (PP&E), Exploration and Evaluation
(E&E) assets, and assets held for sale. |
|
|
|
Cenovus Energy Inc.
Third Quarter 2017 Report |
|
Page 14
Managements Discussion and Analysis |
Revenues
|
|
|
|
|
|
|
($ millions) |
|
Three
Months Ended |
|
|
|
Nine
Months
Ended |
|
|
|
|
Revenues for the Periods Ended September 30, 2016 |
|
2,945 |
|
|
|
7,682 |
Increase (Decrease) due to: |
|
|
|
|
|
|
Oil Sands |
|
1,367 |
|
|
|
2,856 |
Deep Basin |
|
187 |
|
|
|
303 |
Refining and Marketing |
|
(84) |
|
|
|
1,200 |
Corporate and Eliminations |
|
(29) |
|
|
|
(77) |
Revenues for the Periods Ended September 30, 2017 |
|
4,386 |
|
|
|
11,964 |
Combined upstream revenues, excluding revenues from our Conventional segment, rose significantly in the third quarter and
on a year-to-date basis, compared with 2016. The increase was primarily related to a rise in sales volumes due to the Acquisition and the incremental volumes from the
oil sands expansion phases and higher crude oil commodity prices. These increases were partially offset by higher royalties and the strengthening of the Canadian dollar relative to the U.S. dollar. Conventional revenues have been reported in net
earnings from discontinued operations and are discussed below.
Revenues from our Refining and Marketing segment in the third quarter of 2017
decreased by four percent. Refining revenues rose compared with 2016 primarily due to an increase in refined product pricing, partially offset by a decline in refined product output and the strengthening 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 decreased significantly in the three months ended September 30, 2017 compared with 2016 primarily
due to a decrease in purchased products and lower crude oil and natural gas sales prices.
On a year-to-date basis, Refining and Marketing revenues increased 20 percent. Refining revenues rose due to higher refined product pricing, consistent with the rise in average Chicago refined product
benchmark prices, partially offset by decreased refined product output and the strengthening 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 increased in the nine months ended September 30, 2017 compared with 2016 due to higher crude oil and natural gas sales prices and an increase in purchased crude oil and condensate volumes, partially offset by a
decline in natural gas volumes.
Corporate and Eliminations revenues relate to sales and operating revenues between segments and are recorded at
transfer prices based on current market prices.
In the second quarter of 2017, our Conventional segment was classified as a discontinued operation as
we intend to divest all of our legacy Conventional assets. For the three and nine months ended September 30, 2017, Conventional revenues were $286 million and $946 million, respectively (2016 $295 million and
$810 million, respectively). Revenues declined slightly in the third quarter of 2017 due to lower natural gas prices, a rise in royalties, and the strengthening of the Canadian dollar relative to the U.S. dollar, partially offset by higher
crude oil prices. On a year-to-date basis, the increase in revenues compared with 2016 was primarily due to higher commodity prices, partially offset by a rise in
royalties and a decline in sales volumes.
Further information regarding our revenues can be found in the Reportable Segments section of this
MD&A.
Operating Margin
Operating Margin is an additional subtotal found in Note 1 and Note 8 of the interim Consolidated Financial Statements and is used to provide a consistent
measure of the cash generating performance of our assets for comparability of our underlying financial performance between periods. Operating Margin is defined as revenues less purchased product, transportation and blending, operating expenses,
production and mineral taxes plus realized gains less realized losses on risk management activities. Items within the Corporate and Eliminations segment are excluded from the calculation of Operating Margin.
Total Operating Margin
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
September 30, |
|
Nine Months Ended
September 30, |
($ millions) |
|
2017 |
|
|
|
2016 |
|
|
|
2017 |
|
|
|
2016 |
|
|
|
|
|
|
|
|
Revenues |
|
4,790 |
|
|
|
3,329 |
|
|
|
13,232 |
|
|
|
8,737 |
(Add) Deduct: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased Product |
|
1,782 |
|
|
|
2,004 |
|
|
|
6,295 |
|
|
|
5,144 |
Transportation and Blending |
|
1,132 |
|
|
|
473 |
|
|
|
2,692 |
|
|
|
1,364 |
Operating Expenses |
|
644 |
|
|
|
402 |
|
|
|
1,692 |
|
|
|
1,247 |
Production and Mineral Taxes |
|
4 |
|
|
|
4 |
|
|
|
14 |
|
|
|
9 |
Realized (Gain) Loss on Risk Management Activities |
|
12 |
|
|
|
(41) |
|
|
|
95 |
|
|
|
(199) |
Total Operating Margin (1) |
|
1,216 |
|
|
|
487 |
|
|
|
2,444 |
|
|
|
1,172 |
(1) |
Includes results from our Conventional segment, which has been classified as a discontinued operation. |
|
|
|
Cenovus Energy Inc.
Third Quarter 2017 Report |
|
Page 15
Managements Discussion and Analysis |
Three Months Ended September 30, 2017 Compared With September 30, 2016
|
|
|
Total Operating Margin more than doubled in the third quarter of 2017 compared with 2016 primarily due to:
· A significant
increase in our liquids and natural gas sales volumes primarily related to the Acquisition and our oil sands expansion phases;
· A rise in our
average liquids sales price due to improved benchmark prices; and · A higher Operating Margin from Refining and Marketing primarily due to an increase in average market crack spreads and a rise in margins on the sale of our
secondary products, partially offset by narrowing heavy crude oil differentials, and a strengthening of the Canadian dollar relative to the U.S. dollar. |
|
Total Operating Margin by Segment
|
These increases in Operating Margin were partially offset by:
· |
|
A rise in transportation and blending expenses primarily due to higher blending costs related to an increase in
condensate volumes required for blending our increased oil sands production along with higher condensate prices; |
· |
|
An increase in operating expenses primarily due to the Acquisition; |
· |
|
Higher royalties primarily due to an increase in the WTI benchmark price (which determines the royalty rate), an increase
in sales volumes due to the Acquisition, and a rise in our liquids sales price; |
· |
|
Realized risk management losses of $12 million, associated with our upstream assets, compared with gains of
$42 million in the third quarter of 2016; and |
· |
|
A decline in our natural gas sales price from 2016. |
Total Operating Margin Variance
(1) |
Other includes the value of condensate sold as heavy oil blend recorded in revenues and condensate costs recorded in transportation and blending expense. The crude oil price excludes the impact of condensate
purchases. |
|
|
|
Cenovus Energy Inc.
Third Quarter 2017 Report |
|
Page 16
Managements Discussion and Analysis |
Nine Months Ended September 30, 2017 Compared With September 30, 2016
|
|
|
Operating Margin more than doubled in the nine months ended September 30, 2017 compared with 2016 primarily due to:
· A rise in our
average liquids and natural gas sales prices due to improved benchmark prices; · An increase in our liquids sales volumes primarily related to the Acquisition and our 2016 oil sand expansion phases, and a rise in our natural gas sales
volumes primarily due to the acquired Deep Basin Assets; and
· A higher
Operating Margin from Refining and Marketing due to an increase in average market crack spreads, a rise in margins on the sale of our secondary products, and lower realized risk management losses, partially offset by narrowing heavy crude oil
differentials, lower crude utilization rates, and an increase in operating costs. |
|
Total Operating Margin by Segment
|
These increases to Operating Margin were partially offset by:
· |
|
A rise in transportation and blending expenses primarily due to higher blending costs, related to an increase in
condensate volumes required for blending our increased oil sands production along with higher condensate prices; |
· |
|
An increase in operating expenses primarily due to the Acquisition and higher fuel costs related to the increase in
natural gas pricing; |
· |
|
Realized risk management losses of $91 million, associated with our upstream assets, compared with gains of
$222 million in 2016; and |
· |
|
Higher royalties primarily due to an increase in the WTI benchmark price (which determines the royalty rate), a rise in
our liquids sales price, and an increase in sales volumes due to the Acquisition. |
Total Operating
Margin Variance
(1) |
Other includes the value of condensate sold as heavy oil blend recorded in revenues and condensate costs recorded in transportation and blending expense. The crude oil price excludes the impact of condensate
purchases. |
Additional details explaining the changes in Operating Margin can be found in the Reportable Segments section of this
MD&A.
|
|
|
Cenovus Energy Inc.
Third Quarter 2017 Report |
|
Page 17
Managements Discussion and Analysis |
Operating Margin From Continuing Operations
Operating Margin From Continuing Operations excludes results from our Conventional segment, which has been classified as a discontinued operation.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
September 30, |
|
|
|
Nine Months Ended
September 30, |
($ millions) |
|
2017 |
|
|
|
2016 |
|
|
|
2017 |
|
|
|
2016 |
|
|
|
|
|
|
|
|
Revenues |
|
4,504 |
|
|
|
3,034 |
|
|
|
12,286 |
|
|
|
7,927 |
(Add) Deduct: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased Product |
|
1,782 |
|
|
|
2,004 |
|
|
|
6,295 |
|
|
|
5,144 |
Transportation and Blending |
|
1,088 |
|
|
|
429 |
|
|
|
2,543 |
|
|
|
1,228 |
Operating Expenses |
|
526 |
|
|
|
300 |
|
|
|
1,349 |
|
|
|
916 |
Realized (Gain) Loss on Risk Management Activities |
|
9 |
|
|
|
(34) |
|
|
|
76 |
|
|
|
(142) |
Operating Margin From Continuing Operations |
|
1,099 |
|
|
|
335 |
|
|
|
2,023 |
|
|
|
781 |
Cash From Operating Activities and Adjusted Funds Flow
Adjusted Funds 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. Adjusted Funds Flow is defined as Cash From Operating Activities excluding net change in other assets and liabilities and net change in non-cash working capital. Non-cash working capital is composed of current assets and current liabilities, excluding cash and cash equivalents, risk management, the contingent payment, assets held for sale and
liabilities related to assets held for sale. Net change in other assets and liabilities is composed of site restoration costs and pension funding.
Total Cash From Operating Activities and Adjusted Funds Flow
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
September 30, |
|
|
|
Nine Months Ended
September 30, |
($ millions) |
|
2017 |
|
|
|
2016 |
|
|
|
2017 |
|
|
|
2016 |
|
|
|
|
|
|
|
|
Cash From Operating Activities (1) |
|
592 |
|
|
|
310 |
|
|
|
2,159 |
|
|
|
697 |
(Add) Deduct: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Change in Other Assets and Liabilities |
|
(19) |
|
|
|
(13) |
|
|
|
(75) |
|
|
|
(59) |
Net Change in Non-Cash Working Capital |
|
(371) |
|
|
|
(99) |
|
|
|
137 |
|
|
|
(132) |
Adjusted Funds Flow (1) |
|
982 |
|
|
|
422 |
|
|
|
2,097 |
|
|
|
888 |
(1) |
Includes results from our Conventional segment, which has been classified as a discontinued operation.
|
In the third quarter of 2017, Cash From Operating Activities and Adjusted Funds Flow increased primarily as a result of a
higher Operating Margin, as discussed above, partially offset by realized foreign exchange losses on working capital compared with realized foreign exchange gains in 2016, a rise in finance costs primarily associated with additional debt incurred to
finance the Acquisition, and higher general and administrative expenses.
On a
year-to-date basis, Cash From Operating Activities and Adjusted Funds Flow increased compared with 2016 due to a higher Operating Margin, as discussed above, a larger
current tax recovery, and a realized risk management gain on foreign exchange contracts due to hedging activity undertaken to support the Acquisition, partially offset by a rise in finance costs primarily associated with additional debt incurred to
finance the Acquisition and an increase in realized foreign exchange losses on working capital items.
The change in
non-cash working capital for the three months ended September 30, 2017 was due to a decline in accounts payable, a decrease in income tax payable and an increase in accounts receivable. For the three
months ended September 30, 2016, the change in non-cash working capital was due to a decline in accounts payable, a decrease in income tax payable, and a reduction in accounts receivable.
The change in non-cash working capital for the nine months ended September 30, 2017 was primarily due to a
decline in accounts receivable and a reduction in inventory, partially offset by a decrease in accounts payable and an increase in income tax receivable. For the nine months ended September 30, 2016, the change in
non-cash working capital was primarily due to a rise in inventory and an increase in accounts receivable, partially offset by an increase in accounts payable.
|
|
|
Cenovus Energy Inc.
Third Quarter 2017 Report |
|
Page 18
Managements Discussion and Analysis |
Cash From Operating Activities From Continuing Operations and Adjusted Funds Flow From Continuing
Operations
Cash From Operating Activities From Continuing Operations and Adjusted Funds Flow From Continuing Operations excludes results from
our Conventional segment, which has been classified as a discontinued operation.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
|
|
Nine Months Ended September 30, |
($ millions) |
|
2017 |
|
|
|
2016 |
|
|
|
2017 |
|
|
|
2016 |
|
|
|
|
|
|
|
|
Cash From Operating Activities From Continuing Operations |
|
481 |
|
|
|
189 |
|
|
|
1,778 |
|
|
|
404 |
(Add) Deduct: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Change in Other Assets and Liabilities |
|
(15) |
|
|
|
(8) |
|
|
|
(59) |
|
|
|
(47) |
Net Change in Non-Cash Working Capital |
|
(371) |
|
|
|
(99) |
|
|
|
137 |
|
|
|
(132) |
Adjusted Funds Flow From Continuing Operations |
|
867 |
|
|
|
296 |
|
|
|
1,700 |
|
|
|
583 |
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, revaluation
gain, 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.
Total Operating Earnings
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
Nine Months Ended
September 30, |
($ millions) |
|
2017 |
|
|
|
2016 |
|
|
|
2017 |
|
|
|
2016 |
|
|
|
|
|
|
|
|
Earnings (Loss), Before Income Tax (1) |
|
(311) |
|
|
|
(406) |
|
|
|
3,291 |
|
|
|
(1,089) |
Add (Deduct): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized Risk Management (Gain) Loss (2) |
|
486 |
|
|
|
7 |
|
|
|
75 |
|
|
|
440 |
Non-Operating Unrealized Foreign Exchange (Gain) Loss (3) |
|
(367) |
|
|
|
52 |
|
|
|
(702) |
|
|
|
(343) |
Revaluation (Gain) |
|
- |
|
|
|
- |
|
|
|
(2,524) |
|
|
|
- |
(Gain) Loss on Divestiture of Assets |
|
(1) |
|
|
|
5 |
|
|
|
- |
|
|
|
6 |
Loss on Discontinuance |
|
603 |
|
|
|
- |
|
|
|
603 |
|
|
|
- |
Operating Earnings (Loss), Before Income Tax |
|
410 |
|
|
|
(342) |
|
|
|
743 |
|
|
|
(986) |
Income Tax Expense (Recovery) |
|
70 |
|
|
|
(106) |
|
|
|
44 |
|
|
|
(288) |
Operating Earnings (Loss) |
|
340 |
|
|
|
(236) |
|
|
|
699 |
|
|
|
(698) |
(1) |
Includes discontinued operations. |
(2) |
Includes the reversal of unrealized (gains) losses recorded in prior periods. |
(3) |
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 increased in the three
months ended September 30, 2017 compared with 2016 primarily due to higher Cash from Operating Activities and Adjusted Funds Flow, as discussed above, a decrease in depreciation, depletion and amortization (DD&A), higher
unrealized foreign exchange gains on operating items, and the re-measurement of the contingent payment.
Operating Earnings increased in the nine months ended September 30, 2017 compared with 2016 primarily due to higher Cash from Operating Activities
and Adjusted Funds Flow, as discussed above, a decrease in DD&A, unrealized foreign exchange gains on operating items compared with unrealized foreign exchange losses in 2016 and the re-measurement of the
contingent payment.
|
|
|
Cenovus Energy Inc.
Third Quarter 2017 Report |
|
Page 19
Managements Discussion and Analysis |
Operating Earnings From Continuing Operations
Operating Earnings From Continuing Operations excludes results from our Conventional segment, which has been classified as a discontinued operation.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
Nine Months Ended
September 30, |
($ millions) |
|
2017 |
|
|
|
2016 |
|
|
|
2017 |
|
|
|
2016 |
|
|
|
|
|
|
|
|
Earnings (Loss) From Continuing Operations, Before Income Tax |
|
178 |
|
|
|
(121) |
|
|
|
3,701 |
|
|
|
(527) |
Add (Deduct): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized Risk Management (Gain) Loss (1) |
|
486 |
|
|
|
7 |
|
|
|
75 |
|
|
|
440 |
Non-Operating Unrealized Foreign Exchange (Gain) Loss (2) |
|
(367) |
|
|
|
52 |
|
|
|
(702) |
|
|
|
(343) |
Revaluation (Gain) |
|
- |
|
|
|
- |
|
|
|
(2,524) |
|
|
|
- |
(Gain) Loss on Divestiture of Assets |
|
(1) |
|
|
|
5 |
|
|
|
- |
|
|
|
6 |
Operating Earnings (Loss) From Continuing Operations, Before Income Tax |
|
296 |
|
|
|
(57) |
|
|
|
550 |
|
|
|
(424) |
Income Tax Expense (Recovery) |
|
43 |
|
|
|
(17) |
|
|
|
(8) |
|
|
|
(112) |
Operating Earnings (Loss) From Continuing Operations |
|
253 |
|
|
|
(40) |
|
|
|
558 |
|
|
|
(312) |
(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. |
Net Earnings
|
|
|
|
|
|
|
($ millions) |
|
Three Months Ended |
|
|
|
Nine Months Ended |
|
|
|
|
Net Earnings (Loss) for the Periods Ended September 30, 2016 |
|
(251) |
|
|
|
(636) |
Increase (Decrease) due to: |
|
|
|
|
|
|
Operating Margin From Continuing Operations |
|
764 |
|
|
|
1,242 |
Corporate and Eliminations: |
|
|
|
|
|
|
Unrealized Risk Management Gain (Loss) |
|
(479) |
|
|
|
365 |
Unrealized Foreign Exchange Gain (Loss) |
|
490 |
|
|
|
567 |
Revaluation Gain |
|
- |
|
|
|
2,524 |
Re-measurement of Contingent Payment |
|
43 |
|
|
|
109 |
Gain (Loss) on Divestiture of Assets |
|
6 |
|
|
|
6 |
Expenses (1) |
|
(220) |
|
|
|
(97) |
DD&A |
|
(305) |
|
|
|
(489) |
Exploration Expense |
|
- |
|
|
|
1 |
Income Tax Recovery (Expense) |
|
44 |
|
|
|
(898) |
Net Earnings (Loss) From Discontinued Operations |
|
(161) |
|
|
|
88 |
Net Earnings (Loss) for the Periods Ended September 30, 2017 |
|
(69) |
|
|
|
2,782 |
(1) |
Includes realized risk management (gains) losses, general and administrative, finance costs, interest income, realized
foreign exchange (gains) losses, transaction costs, research costs, other (income) loss, net, and Corporate and Eliminations revenues, purchased product, transportation and blending, and operating expenses. |
Net loss for the three and nine months ended September 30, 2017 includes a $440 million after-tax loss
on the divestiture of our Pelican Lake assets and the adjacent Grand Rapids project. Net loss in the third quarter decreased compared with 2016 primarily due to:
· |
|
Higher Operating Earnings, as discussed above; |
· |
|
Non-operating unrealized foreign exchange gains of $367 million primarily
related to the translation of our U.S. dollar denominated debt compared with unrealized losses of $52 million in 2016; and |
· |
|
A deferred income tax recovery compared with an expense in 2016. |
These decreases to our net loss were partially offset by unrealized risk management losses of $486 million compared with $7 million in the third
quarter of 2016.
Net earnings improved significantly for the nine months ended September 30, 2017 primarily due to:
· |
|
The revaluation gain of $2,524 million related to the deemed disposition of our
pre-existing interest in FCCL; |
· |
|
Higher Operating Earnings, as discussed above; |
· |
|
Non-operating unrealized foreign exchange gains of $702 million compared
with $343 million in 2016; and |
· |
|
Unrealized risk management losses of $75 million compared with $440 million in 2016. |
These increases were partially offset by a deferred income tax expense primarily due to the gain on the revaluation of our
pre-existing interest in FCCL compared with a recovery in 2016.
|
|
|
Cenovus Energy Inc.
Third Quarter 2017 Report |
|
Page 20
Managements Discussion and Analysis |
Net Capital Investment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
|
|
Nine Months Ended
September 30, |
($ millions) |
|
2017 |
|
|
|
2016 |
|
|
|
2017 |
|
|
|
2016 |
|
|
|
|
|
|
|
|
Oil Sands |
|
273 |
|
|
|
110 |
|
|
|
660 |
|
|
|
476 |
Deep Basin |
|
64 |
|
|
|
- |
|
|
|
77 |
|
|
|
- |
Conventional |
|
42 |
|
|
|
41 |
|
|
|
180 |
|
|
|
114 |
Refining and Marketing |
|
38 |
|
|
|
51 |
|
|
|
124 |
|
|
|
156 |
Corporate and Eliminations |
|
21 |
|
|
|
6 |
|
|
|
37 |
|
|
|
21 |
Capital Investment |
|
438 |
|
|
|
208 |
|
|
|
1,078 |
|
|
|
767 |
Acquisitions (1) |
|
70 |
|
|
|
- |
|
|
|
18,301 |
|
|
|
11 |
Divestitures (1) |
|
(943) |
|
|
|
(8) |
|
|
|
(943) |
|
|
|
(8) |
Net Capital Investment (2) |
|
(435) |
|
|
|
200 |
|
|
|
18,436 |
|
|
|
770 |
(1) |
In connection with the Acquisition that was completed in the second quarter of 2017, Cenovus was deemed to have
disposed of its pre-existing interest in FCCL and re-acquired it at fair value as required by IFRS 3, Business Combinations (IFRS 3), which is
not reflected in the table above. The carrying value of the pre-existing interest was $9,081 million and the estimated fair value was $11,605 million as at May 17, 2017.
|
(2) |
Includes expenditures on PP&E, E&E assets and, assets held for sale. |
Capital investment in the three and nine months ended September 30, 2017 increased $230 million and $311 million, respectively, compared
with 2016. On a year-to-date basis in 2017, Oil Sands capital investment focused on sustaining capital related to existing production; Christina Lake expansion phase G;
and stratigraphic test wells to determine pad placement for sustaining wells, near-term expansion phases, and progression of certain emerging assets. Deep Basin capital investment for the 137 days of ownership related to asset development planning
and the commencement of our horizontal drilling program, targeting liquids rich gas within the Deep Basin corridor. In 2017, Conventional capital investment focused on sustaining capital and the tight oil drilling program in southern Alberta. We
wound down our drilling program early in the third quarter due to the pending sale of our Conventional assets. Capital investment in the Refining and Marketing segment related to capital maintenance and reliability work.
Further information regarding our capital investment can be found in the Reportable Segments section of this MD&A.
Capital Investment Decisions
In the short-term, we are acutely focused on completing the divestiture of our legacy Conventional assets in order to deleverage our balance sheet. To
date, we have announced divestitures totaling approximately $2.8 billion in gross proceeds. We closed the first divestiture, Pelican Lake and the adjacent Grand Rapids project, in the third quarter of 2017 and have used the net proceeds to pay
down the committed Bridge Facility. In addition to our commitment to reduce our debt, we are actively identifying cost savings opportunities.
With
balance sheet leverage more in line with our strategy, our long-term disciplined approach to capital allocation includes prioritizing our uses of cash in the following manner:
· |
|
First, to sustaining and maintenance capital for our existing business operations; |
· |
|
Second, to paying our current dividend as part of providing strong total shareholder return; and |
· |
|
Third, for growth or discretionary capital. |
Our approach to capital allocation includes evaluating all opportunities using specific rigorous criteria with the objective of maintaining a prudent and
flexible capital structure and strong balance sheet metrics, which position us to be financially resilient in times of lower cash flows. In addition, we continue to evaluate other corporate and financial opportunities, including generating cash from
our existing portfolio. Refer to the Liquidity and Capital Resources section of this MD&A for further information.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
Nine Months Ended
September 30, |
($ millions) |
|
2017 |
|
|
|
2016 |
|
|
|
2017 |
|
|
|
2016 |
Adjusted Funds Flow (1) |
|
982 |
|
|
|
422 |
|
|
|
2,097 |
|
|
|
888 |
Capital Investment (Sustaining and Growth) |
|
438 |
|
|
|
208 |
|
|
|
1,078 |
|
|
|
767 |
Free Funds Flow (1) (2) |
|
544 |
|
|
|
214 |
|
|
|
1,019 |
|
|
|
121 |
Cash Dividends |
|
62 |
|
|
|
41 |
|
|
|
164 |
|
|
|
124 |
|
|
482 |
|
|
|
173 |
|
|
|
855 |
|
|
|
(3) |
(1) |
Includes discontinued operations. |
(2) |
Free Funds Flow is a non-GAAP measure defined as Adjusted Funds Flow less
capital investment. |
For the nine months ended September 30, 2016, capital investment and cash dividends in excess of
Adjusted Funds Flow was funded through our cash balance on hand.
|
|
|
Cenovus Energy Inc.
Third Quarter 2017 Report |
|
Page 21
Managements Discussion and Analysis |
We updated our 2017 guidance estimates upon further review of our capital program to reflect ongoing cost
savings, efficiency improvements, divestiture activities, and our continued focus on capital discipline. Capital spend for 2017 is now expected to be between approximately $1.55 billion and $1.65 billion, a reduction of six percent from
July 26, 2017.
REPORTABLE SEGMENTS
|
|
|
|
|
Our reportable segments are as follows:
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 Telephone Lake. Our interest in certain of our operated oil sands properties, notably Foster Creek, Christina Lake and Narrows Lake
increased from 50 percent to 100 percent on May 17, 2017.
Deep Basin, which includes approximately three million net acres of land primarily in the Elmworth-Wapiti, Kaybob-Edson, and Clearwater operating
areas, rich in natural gas and natural gas liquids. The assets reside in Alberta and British Columbia and include interests in numerous natural gas processing facilities. The Deep Basin Assets were acquired on May 17, 2017.
Conventional, which has been classified as a discontinued
operation as we commenced marketing for sale our Conventional assets. This segment 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 CO2 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. |
|
|
|
|
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 reportable 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 (1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
September 30, |
|
|
|
Nine Months Ended
September 30, |
($ millions) |
|
2017 |
|
|
|
2016 |
|
|
|
2017 |
|
|
|
2016 |
|
|
|
|
|
|
|
|
Oil Sands (2) |
|
2,156 |
|
|
|
789 |
|
|
|
4,821 |
|
|
|
1,965 |
Deep Basin (3) |
|
187 |
|
|
|
- |
|
|
|
303 |
|
|
|
- |
Refining and Marketing |
|
2,161 |
|
|
|
2,245 |
|
|
|
7,162 |
|
|
|
5,962 |
Corporate and Eliminations |
|
(118) |
|
|
|
(89) |
|
|
|
(322) |
|
|
|
(245) |
|
|
4,386 |
|
|
|
2,945 |
|
|
|
11,964 |
|
|
|
7,682 |
(1) |
In the second quarter of 2017, we announced our intention to divest the Conventional segment assets. As a result, the
Conventional segment was classified as a discontinued operation. For the three and nine months ended September 30, 2017, revenues related to discontinued operations were $286 million and $946 million, respectively (2016
$295 million and $810 million, respectively). |
(2) |
Our 2017 results include 137 days of FCCL operations at 100 percent. See the Oil Sands segment section of this
MD&A for more details. |
(3) |
Our 2017 results include 137 days of operations from the Deep Basin Assets. See the Deep Basin segment section of this
MD&A for more details. |
|
|
|
Cenovus Energy Inc.
Third Quarter 2017 Report |
|
Page 22
Managements Discussion and Analysis |
OIL SANDS
In northeastern Alberta, we now own 100 percent of the Foster Creek, Christina Lake and Narrows Lake oil sands projects following the completion of
the Acquisition. We have several emerging projects in the early stages of development, including our 100 percent-owned project at Telephone Lake. 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 the third quarter of 2017 compared with 2016 include:
· |
|
More than doubling our crude oil production primarily due to the Acquisition and incremental production volumes from
Christina Lake phase F and Foster Creek phase G, both of which started-up in the second half of 2016; |
· |
|
Crude oil netbacks, excluding realized risk management activities, of $24.73 per barrel, a 55 percent increase from
the third quarter of 2016; and |
· |
|
Generating Operating Margin net of capital investment of $551 million, an increase of $394 million.
|
Oil Sands Crude Oil
Three Months Ended September 30, 2017 Compared With September 30, 2016
Financial Results
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
($ millions) |
|
2017 |
|
|
|
|
2016 |
Gross Sales |
|
2,204 |
|
|
|
|
|
788 |
Less: Royalties |
|
54 |
|
|
|
|
|
4 |
Revenues |
|
2,150 |
|
|
|
|
|
784 |
Expenses |
|
|
|
|
|
|
|
|
Transportation and Blending |
|
1,066 |
|
|
|
|
|
429 |
Operating |
|
254 |
|
|
|
|
|
125 |
(Gain) Loss on Risk Management |
|
9 |
|
|
|
|
|
(35) |
Operating Margin |
|
821 |
|
|
|
|
|
265 |
Capital Investment |
|
270 |
|
|
|
|
|
107 |
Operating Margin Net of Related Capital Investment |
|
551 |
|
|
|
|
|
158 |
Operating Margin 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
Price
In the third quarter of
2017, our average crude oil sales price increased to $40.02 per barrel (2016 $31.30 per barrel). The rise in our crude oil price was consistent with the increase in the WCS and Christina Dilbit Blend (CDB) benchmark prices
and the narrowing of the WCS-Condensate differential, partially offset by the strengthening of the Canadian dollar relative to the U.S. dollar. The WCS-CDB differential
narrowed to a discount of US$1.47 per barrel (2016 discount of US$2.05 per barrel).
Our crude oil sales price is influenced by the cost of
condensate used in blending. Our blending ratios range between 25 percent and 33 percent. As the cost of condensate increases relative to the price of blended crude oil, our bitumen sales price decreases. Due to high demand for condensate
at Edmonton, we also purchase condensate from U.S. markets. As such, our average cost of condensate is generally higher than the Edmonton benchmark
|
|
|
Cenovus Energy Inc.
Third Quarter 2017 Report |
|
Page 23
Managements Discussion and Analysis |
price due to transportation between market hubs and transportation to field locations. In addition, up to
three months may elapse from when we purchase condensate to when we blend it with our production. In a rising price environment, we expect to see some benefit in our bitumen sales price as we are using condensate purchased at a lower price earlier
in the year.
Production Volumes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
(barrels per day) |
|
2017 |
|
|
|
|
Percent
Change |
|
|
|
|
2016 |
Foster Creek |
|
154,363 |
|
|
|
|
|
109% |
|
|
|
|
|
73,798 |
Christina Lake |
|
208,131 |
|
|
|
|
|
161% |
|
|
|
|
|
79,793 |
|
|
362,494 |
|
|
|
|
|
136% |
|
|
|
|
|
153,591 |
Production at Foster Creek was higher compared with 2016 primarily due to the Acquisition and incremental production
volumes from the phase G expansion, partially offset by reduced volumes as a result of temporary treating issues which were resolved by the end of the quarter.
Production from Christina Lake increased in the three months ended September 30, 2017 compared with 2016 primarily due to the Acquisition and
incremental production volumes from the phase F expansion.
Condensate
The bitumen currently produced by Cenovus must be blended with condensate to reduce its thickness in order to transport it to market through pipelines.
Revenues represent the total value of blended crude oil sold and include the value of condensate. Consistent with the narrowing of the WCS-Condensate differential during the third quarter of 2017, the
proportion of the cost of condensate recovered increased. The amount of condensate used increased as a result of the Acquisition.
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 sales prices. Net profits are a function of sales volumes, sales prices and allowed operating and capital costs. In 2017, our royalty calculation was based on
net profits as compared with a calculation based on gross revenues in 2016.
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
|
|
|
|
|
|
|
Three Months Ended September 30, |
(percent) |
|
2017 |
|
2016 |
Foster Creek |
|
9.1 |
|
0.8 |
Christina Lake |
|
1.6 |
|
1.6 |
Royalties increased $50 million in the third quarter compared with 2016, primarily due to a higher WTI benchmark
price (which determines the royalty rate), rise in sales volumes, and an increase in crude oil sales prices. As noted above, the Foster Creek royalty calculation was based on net profits as compared with a calculation based on gross revenues for
2016, resulting in a significant increase in the royalty rate.
Expenses
Transportation and Blending
Transportation and blending costs increased $637 million. Blending costs increased due to a rise in condensate volumes required for our increased
production and higher condensate prices. Our condensate costs were higher than the average Edmonton benchmark price in the third quarter of 2017, primarily due to the transportation expense associated with moving the condensate between market hubs
and to our oil sands projects.
|
|
|
Cenovus Energy Inc.
Third Quarter 2017 Report |
|
Page 24
Managements Discussion and Analysis |
Transportation costs increased primarily due to higher sales volumes as a result of the Acquisition and
incremental production volumes from the expansion phases. To help ensure adequate capacity for our expected production growth, we have capacity commitments in excess of our current production. Production growth is expected to reduce our per-barrel transportation costs.
In addition, rail costs rose as a result of moving higher volumes by rail and
transporting more volumes longer distances to U.S. markets. We transported an average of 9,958 barrels per day of crude oil by rail (2016 7,573 barrels per day).
Per-unit Transportation Expenses
At Foster Creek, per-barrel transportation costs rose due to an increase in rail costs related to higher volumes
shipped to the U.S. by unit trains, partially offset by an increase in the proportion of Canadian to U.S. sales resulting in lower costs associated with pipeline tariffs.
At Christina Lake, transportation costs decreased primarily due to a revision to prior period toll charges and an increase in the proportion of Canadian
to U.S. sales resulting in lower costs associated with pipeline tariffs.
Operating
Primary drivers of our operating expenses for the third quarter of 2017 were workforce costs, fuel, chemical costs, workovers and repairs and maintenance.
Total operating expenses increased $129 million primarily due to the Acquisition, partially offset by a decline in fuel costs associated with a decrease in the natural gas price.
Per-unit Operating Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
($/bbl) |
|
2017 |
|
|
|
Percent
Change |
|
|
|
2016 |
Foster Creek |
|
|
|
|
|
|
|
|
|
|
Fuel |
|
2.10 |
|
|
|
(14)% |
|
|
|
2.44 |
Non-fuel |
|
7.43 |
|
|
|
3% |
|
|
|
7.19 |
Total |
|
9.53 |
|
|
|
(1)% |
|
|
|
9.63 |
Christina Lake |
|
|
|
|
|
|
|
|
|
|
Fuel |
|
1.78 |
|
|
|
(17)% |
|
|
|
2.14 |
Non-fuel |
|
4.30 |
|
|
|
(23)% |
|
|
|
5.58 |
Total |
|
6.08 |
|
|
|
(21)% |
|
|
|
7.72 |
Total |
|
7.58 |
|
|
|
(12)% |
|
|
|
8.65 |
At Foster Creek, per-barrel fuel costs decreased compared with 2016 primarily due
to lower natural gas prices. Per-barrel non-fuel operating expenses increased primarily due to increased workover activities due to pump changes, partially offset by an
increase in production.
At Christina Lake, fuel costs decreased on a per-barrel basis in 2017 primarily due
to lower fuel consumption. Non-fuel per-barrel operating expenses declined primarily due to higher production, partially offset by higher workforce and chemicals costs
associated with the phase F expansion, increased workover activities due to pump changes, and increased repairs and maintenance activities.
Netbacks (1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foster Creek |
|
|
|
Christina Lake |
|
|
Three Months Ended September 30, |
($/bbl) |
|
2017 |
|
|
|
2016 |
|
|
|
2017 |
|
|
|
2016 |
Sales Price |
|
41.57 |
|
|
|
33.61 |
|
|
|
38.84 |
|
|
|
29.11 |
Royalties |
|
2.98 |
|
|
|
0.19 |
|
|
|
0.55 |
|
|
|
0.41 |
Transportation and Blending |
|
8.68 |
|
|
|
8.38 |
|
|
|
4.14 |
|
|
|
4.49 |
Operating Expenses |
|
9.53 |
|
|
|
9.63 |
|
|
|
6.08 |
|
|
|
7.72 |
Netback Excluding Realized Risk Management |
|
20.38 |
|
|
|
15.41 |
|
|
|
28.07 |
|
|
|
16.49 |
Realized Risk Management Gain (Loss) |
|
(0.13) |
|
|
|
2.37 |
|
|
|
(0.40) |
|
|
|
2.38 |
Netback Including Realized Risk Management |
|
20.25 |
|
|
|
17.78 |
|
|
|
27.67 |
|
|
|
18.87 |
(1) |
Netbacks reflect our margin on a per-barrel basis of unblended crude oil. |
Risk Management
Risk management activities in the third quarter of 2017 resulted in realized losses of $9 million (2016 realized gains of $35 million),
consistent with average benchmark prices exceeding our contract prices.
|
|
|
Cenovus Energy Inc.
Third Quarter 2017 Report |
|
Page 25
Managements Discussion and Analysis |
Nine Months Ended September 30, 2017 Compared With September 30, 2016
Financial Results
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, |
($ millions) |
|
2017 |
|
|
|
2016 |
Gross Sales |
|
4,920 |
|
|
|
1,960 |
Less: Royalties |
|
117 |
|
|
|
7 |
Revenues |
|
4,803 |
|
|
|
1,953 |
Expenses |
|
|
|
|
|
|
Transportation and Blending |
|
2,511 |
|
|
|
1,228 |
Operating |
|
608 |
|
|
|
348 |
(Gain) Loss on Risk Management |
|
72 |
|
|
|
(165) |
Operating Margin |
|
1,612 |
|
|
|
542 |
Capital Investment |
|
654 |
|
|
|
472 |
Operating Margin Net of Related Capital Investment |
|
958 |
|
|
|
70 |
Operating Margin 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
Price
In the nine months ended September 30, 2017, our average crude oil sales price increased significantly to $39.52 per barrel
(2016 $24.28 per barrel). The significant rise in our crude oil price was consistent with the increase in the WCS and CDB benchmark prices and the narrowing of the WCS-Condensate differential,
partially offset by the strengthening of the Canadian dollar relative to the U.S. dollar. The WCS-CDB differential narrowed to a discount of US$1.60 per barrel (2016 discount of US$2.22 per barrel).
Production Volumes
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, |
(barrels per day) |
|
2017 |
|
|
|
Percent Change |
|
|
|
2016 |
|
|
|
|
|
|
Foster Creek |
|
114,632 |
|
|
|
73% |
|
|
|
66,435 |
Christina Lake |
|
154,634 |
|
|
|
97% |
|
|
|
78,321 |
|
|
269,266 |
|
|
|
86% |
|
|
|
144,756 |
Production at Foster Creek was higher compared with 2016 due to the Acquisition and incremental production volumes from
the phase G expansion, partially offset by reduced volumes as a result of temporary treating issues and a 20-day planned turnaround which reduced average production by 3,690 barrels per day. The planned
turnaround was the largest scale turnaround executed to date at Foster Creek.
Production from Christina Lake increased in the nine months ended
September 30, 2017 primarily due to the Acquisition and incremental production volumes from the phase F expansion.
The year-to-date increase in production volumes at Foster Creek and Christina Lake due to the Acquisition was 38,203 barrels per day and 52,685 barrels per day, respectively.
|
|
|
Cenovus Energy Inc.
Third Quarter 2017 Report |
|
Page 26
Managements Discussion and Analysis |
Royalties
Effective Royalty Rates
|
|
|
|
|
|
|
Nine Months Ended September 30, |
(percent) |
|
2017 |
|
2016 |
Foster Creek |
|
8.4 |
|
0.5 |
Christina Lake |
|
2.1 |
|
1.4 |
Royalties increased $110 million. Royalties at Foster Creek increased primarily due to a higher WTI benchmark price
(which determines the royalty rate). The royalty calculation was based on net profits as compared with a calculation based on gross revenues for 2016, resulting in a significant increase in the royalty rate. In 2016, the low royalty rate was
primarily due to low crude oil sales prices and a true-up of the 2015 royalty calculation.
Christina Lake
royalties increased in 2017 primarily as a result of a rise in the WTI benchmark price (which determines the royalty rate), higher sales prices and an increase in sales volumes.
Expenses
Transportation and Blending
Transportation and blending costs increased $1,283 million. Blending costs increased
due to a rise in condensate volumes required for our increased production along with higher condensate prices. Our condensate costs were higher than the average Edmonton benchmark price in the nine months ended September 30, 2017, primarily due
to the transportation expense associated with moving the condensate between market hubs and to our oil sands projects.
Transportation costs increased
primarily due to higher sales volumes related to the incremental production volumes from the Acquisition and expansion phases.
In addition, rail
costs rose as a result of moving higher volumes by rail over longer distances to U.S. markets. We transported an average of 7,842 barrels per day of crude oil by rail (2016 5,106 barrels per day).
Per-unit Transportation Expenses
At Foster Creek, per-barrel transportation costs declined primarily due to an increase in the proportion of
Canadian to U.S. sales resulting in lower costs associated with pipeline tariffs, partially offset by an increase in rail costs related to an increase in volumes shipped to the U.S. by unit trains.
At Christina Lake, transportation costs decreased primarily due to an increase in the proportion of Canadian to U.S. sales resulting in lower costs
associated with pipeline tariffs, and a revision to prior period toll charges.
Operating
Primary drivers of our operating expenses in the nine months ended September 30, 2017 were workforce costs, fuel, repairs and maintenance, chemical
costs and workovers. Total operating expenses increased $260 million primarily due to the Acquisition, higher fuel costs with the rise in natural gas prices, additional repairs and maintenance, and fluid, waste handling and trucking costs
related to the turnaround at Foster Creek and increased workforce and chemical costs associated with the phase F expansion at Christina Lake.
Per-unit Operating Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, |
($/bbl) |
|
2017 |
|
|
|
Percent
Change |
|
|
|
2016 |
Foster Creek |
|
|
|
|
|
|
|
|
|
|
Fuel |
|
2.53 |
|
|
|
15% |
|
|
|
2.20 |
Non-fuel |
|
7.96 |
|
|
|
(4)% |
|
|
|
8.32 |
Total |
|
10.49 |
|
|
|
-% |
|
|
|
10.52 |
Christina Lake |
|
|
|
|
|
|
|
|
|
|
Fuel |
|
2.14 |
|
|
|
16% |
|
|
|
1.85 |
Non-fuel |
|
4.66 |
|
|
|
(14)% |
|
|
|
5.39 |
Total |
|
6.80 |
|
|
|
(6)% |
|
|
|
7.24 |
Total |
|
8.40 |
|
|
|
(4)% |
|
|
|
8.74 |
At Foster Creek, per-barrel fuel costs increased primarily due to the rise in
natural gas prices. Per-barrel non-fuel operating expenses declined primarily due to higher production, partially offset by higher repairs and maintenance, and fluid,
waste handling and trucking costs related to turnaround activities, and an increase in workover costs due to pump changes.
|
|
|
Cenovus Energy Inc.
Third Quarter 2017 Report |
|
Page 27
Managements Discussion and Analysis |
At Christina Lake, fuel costs rose on a per-barrel basis due to a
rise in natural gas prices, partially offset by a decrease in fuel consumption. Per-barrel non-fuel operating expenses decreased primarily due to higher production,
partially offset by increased workforce and chemical costs associated with the phase F expansion, and higher repairs and maintenance activities.
Netbacks (1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foster Creek |
|
|
|
Christina Lake |
|
|
Nine Months Ended September 30, |
($/bbl) |
|
2017 |
|
|
|
2016 |
|
|
|
2017 |
|
|
|
2016 |
|
|
|
|
|
|
|
|
Sales Price |
|
42.22 |
|
|
|
26.97 |
|
|
|
37.47 |
|
|
|
22.01 |
Royalties |
|
2.80 |
|
|
|
0.10 |
|
|
|
0.71 |
|
|
|
0.25 |
Transportation and Blending |
|
9.01 |
|
|
|
9.43 |
|
|
|
4.12 |
|
|
|
4.89 |
Operating Expenses |
|
10.49 |
|
|
|
10.52 |
|
|
|
6.80 |
|
|
|
7.24 |
Netback Excluding Realized Risk Management |
|
19.92 |
|
|
|
6.92 |
|
|
|
25.84 |
|
|
|
9.63 |
Realized Risk Management Gain (Loss) |
|
(1.05) |
|
|
|
4.37 |
|
|
|
(0.96) |
|
|
|
3.95 |
Netback Including Realized Risk Management |
|
18.87 |
|
|
|
11.29 |
|
|
|
24.88 |
|
|
|
13.58 |
(1) |
Netbacks reflect our margin on a per-barrel basis of unblended crude oil. |
Risk Management
Risk management activities on a year-to-date basis in 2017 resulted in
realized losses of $72 million (2016 realized gains of $165 million), consistent with average benchmark prices exceeding our contract 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 the three and nine months ended September 30, 2017, net of internal usage, was 6 MMcf per day and 11 MMcf per day, respectively (2016 18 MMcf per day and 17 MMcf per day,
respectively).
Operating Margin from our Oil Sands natural gas production was $nil in the third quarter of 2017, a decrease of $3 million
compared with 2016, due to lower natural gas sales prices and a decline in natural gas volumes. On a year-to-date basis, the Operating Margin was $3 million, a
decrease of $1 million compared with 2016, due to lower natural gas volumes, partially offset by higher natural gas sales prices.
Oil Sands Capital Investment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
|
|
Nine Months Ended
September 30, |
($ millions) |
|
2017 |
|
|
|
2016 |
|
|
|
2017 |
|
|
|
2016 |
|
|
|
|
|
|
|
|
Foster Creek |
|
122 |
|
|
|
54 |
|
|
|
312 |
|
|
|
211 |
Christina Lake |
|
132 |
|
|
|
47 |
|
|
|
272 |
|
|
|
222 |
|
|
254 |
|
|
|
101 |
|
|
|
584 |
|
|
|
433 |
Narrows Lake |
|
3 |
|
|
|
1 |
|
|
|
11 |
|
|
|
6 |
Telephone Lake |
|
3 |
|
|
|
3 |
|
|
|
32 |
|
|
|
13 |
Grand Rapids |
|
- |
|
|
|
- |
|
|
|
1 |
|
|
|
5 |
Other (1) |
|
13 |
|
|
|
5 |
|
|
|
32 |
|
|
|
19 |
Capital Investment (2) |
|
273 |
|
|
|
110 |
|
|
|
660 |
|
|
|
476 |
(1) |
Includes new resource plays and Athabasca natural gas. |
(2) |
Includes expenditures on PP&E, E&E assets, and assets held for sale. |
Existing Projects
Capital investment reflects our 100 percent ownership of FCCL from May 17, 2017 forward. Capital investment at Foster Creek in 2017 focused on
sustaining capital related to existing production and stratigraphic test wells. In 2016, capital investment was low due to spending reductions in response to the low commodity price environment. Capital was also invested in 2016 to complete Foster
Creek phase G.
In 2017, Christina Lake capital investment related to sustaining capital related to existing production, the phase G expansion and
stratigraphic test wells. In 2016, capital was focused on sustaining capital related to existing production, the completion of expansion phase F and stratigraphic test wells.
Capital investment at Narrows Lake on a year-to-date basis in 2017 related
to drilling of stratigraphic test wells to further progress the project.
Emerging Projects
In 2017, Telephone Lake capital investment concentrated on the drilling of stratigraphic test wells to further assess the project. In 2016, spending was
reduced in response to the low commodity price environment and focused on front-end engineering work for the central processing facility.
|
|
|
Cenovus Energy Inc.
Third Quarter 2017 Report |
|
Page 28
Managements Discussion and Analysis |
Drilling Activity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross Stratigraphic
Test Wells |
|
|
|
|
Gross Production
Wells (1) |
Nine Months Ended September 30, |
|
2017 |
|
|
|
|
2016 |
|
|
|
|
2017 |
|
|
|
2016 |
Foster Creek |
|
93 |
|
|
|
|
|
95 |
|
|
|
|
|
25 |
|
|
|
18 |
Christina Lake |
|
105 |
|
|
|
|
|
97 |
|
|
|
|
|
8 |
|
|
|
24 |
|
|
198 |
|
|
|
|
|
192 |
|
|
|
|
|
33 |
|
|
|
42 |
Narrows Lake |
|
2 |
|
|
|
|
|
- |
|
|
|
|
|
- |
|
|
|
- |
Telephone Lake |
|
13 |
|
|
|
|
|
- |
|
|
|
|
|
- |
|
|
|
- |
Other |
|
1 |
|
|
|
|
|
5 |
|
|
|
|
|
- |
|
|
|
- |
|
|
214 |
|
|
|
|
|
197 |
|
|
|
|
|
33 |
|
|
|
42 |
(1) |
SAGD well pairs are counted as a single producing well. |
Stratigraphic test wells were drilled to
help identify well pad locations for sustaining wells and near-term expansion phases and to further progress the evaluation of emerging assets.
Future Capital
Investment
We updated our 2017 guidance estimates upon further review of our capital program. Our revised full-year 2017 Oil Sands capital
investment is forecast to be between $945 million and $1,015 million. Guidance has decreased from July 26, 2017 by approximately eight percent to reflect ongoing cost savings, efficiency improvements and our continued focus on capital
discipline.
Foster Creek is currently producing from phases A through G. Capital investment for 2017 is forecast to be between $450 million and
$475 million. We plan to continue focusing on sustaining capital related to existing production and to progress phase H, a potential 40,000 barrels per day phase, towards being sanction ready.
Christina Lake is producing from phases A through F. Capital investment for 2017 is forecast to be between $425 million and $450 million,
focused on sustaining capital and construction of the phase G expansion. Field construction of phase G, which has an initial design capacity of 50,000 barrels per day, is progressing well and remains on track. Phase G is expected to start
producing in the second half of 2019.
Capital investment at our Narrows Lake and new resource plays in 2017 is forecast to be between
$70 million and $90 million, focusing on stratigraphic test well programs at Telephone Lake and engineering and equipment preservation related to the suspension of construction at Narrows Lake.
DD&A and Exploration Expense
We deplete crude oil and
natural gas properties on a unit-of-production basis over proved reserves. The
unit-of-production rate takes into account expenditures incurred to date, together with future development expenditures required to develop those proved reserves. This
rate, calculated at an area level, is then applied to our sales volume to determine DD&A in a given period. We believe that this method of calculating DD&A charges each barrel of crude oil equivalent sold with its proportionate share of the
cost of capital invested over the total estimated life of the related asset as represented by proved reserves.
The following calculation illustrates
how the implied depletion rate for our total upstream assets could be determined using the reported consolidated data and includes our Conventional segment, which has been classified as held for sale. Once classified as held for sale depletion
stops.
|
|
|
($ millions, unless otherwise indicated) |
|
As at
December 31, 2016 |
|
|
Upstream Property, Plant and Equipment Carrying Value |
|
11,878 |
Estimated Future Development Capital |
|
18,378 |
Total Estimated Upstream Cost Base |
|
30,256 |
Total Proved Reserves (MMBOE) |
|
2,667 |
Implied Depletion Rate ($/BOE) |
|
11.34 |
While this illustrates the calculation of the implied depletion rate, our depletion rates result in a total average rate
ranging between $9.55 to $10.00 per BOE. Amounts related to assets under construction and discontinued operations which would be included in the total upstream cost base and would have proved reserves attributed to them, are not depleted. Property
specific rates will exclude upstream assets that are depreciated on a straight-line basis. As such, our actual depletion will differ from depletion calculated by applying the above implied depletion rate. Further information on our accounting policy
for DD&A is included in our notes to the December 31, 2016 Consolidated Financial Statements.
In the three and nine months ended
September 30, 2017, Oil Sands DD&A increased $212 million and $351 million, respectively, from 2016. The increase was due to higher sales volumes primarily due to the Acquisition. The average depletion rate on a year-to-date basis in 2017 was approximately $11.24 per barrel compared with $11.55 per barrel in 2016. Our DD&A rate decreased due to proved reserves additions and lower
|
|
|
Cenovus Energy Inc.
Third Quarter 2017 Report |
|
Page 29
Managements Discussion and Analysis |
future development costs. The decrease in DD&A rates was partially offset by an increase in the carrying value of our assets due to the re-measurement
of our pre-existing interest in FCCL and the acquisition of the additional 50 percent interest.
Future
development costs declined due to cost savings at both Foster Creek and Christina Lake related to a reduction in per well costs and increased well pair spacing. This decline was partially offset by an increase in costs related to the expansion of
the development area and inclusion of phase G costs at Christina Lake.
For the three and nine months ended September 30, 2017, we recorded
exploration expense of $1 million (2016 $1 million and $2 million, respectively).
Assets and Liabilities Held for Sale
On September 29, 2017, we closed the sale of our Pelican Lake assets, including the adjacent Grand Rapids project.
DEEP BASIN
On May 17, 2017,
we acquired the majority of ConocoPhillips western Canadian conventional crude oil and natural gas assets including undeveloped land, exploration and production assets, and related infrastructure in Alberta and British Columbia. Our Deep Basin
Assets include approximately three million net acres of land primarily in the Elmworth-Wapiti, Kaybob-Edson, and Clearwater operating areas, with an average 70 percent working interest. In addition, the Deep Basin Assets include interests in
numerous natural gas processing plants with an estimated net processing capacity of 1.4 Bcf per day. The Deep Basin Assets are expected to provide short-cycle development opportunities with high return potential that complement our long-term oil
sands development. Deep Basin production is expected to provide an economic hedge for the natural gas required as a fuel source at both our oil sands and refining operations, as well as NGLs that could be used as inputs for future solvent aided oil
sands projects.
The safe and efficient integration of the Deep Basin Assets continues to be a top priority for Cenovus. We are committed to ensuring
strong stakeholder and community relations as we establish ourselves as a new operator in the Deep Basin area.
Significant developments that impacted
our Deep Basin segment in the third quarter of 2017 included:
· |
|
Total capital investment of $64 million related to the drilling of 10 horizontal production wells targeting liquids
rich gas, the completion of four wells, and the tie-in of three wells; |
· |
|
Netbacks of $5.34 per BOE; |
· |
|
Total production averaging 115,301 BOE per day; |
· |
|
Revenues of $187 million; and |
· |
|
Total operating costs of $101 million or $9.00 per BOE. |
Financial Results
|
|
|
|
|
|
|
($ millions) |
|
Three Months Ended
September 30, 2017 |
|
|
|
May 17
September 30, 2017 |
|
|
|
|
Gross Sales |
|
200 |
|
|
|
324 |
Less: Royalties |
|
13 |
|
|
|
21 |
Revenues |
|
187 |
|
|
|
303 |
Expenses |
|
|
|
|
|
|
Transportation and Blending |
|
22 |
|
|
|
32 |
Operating |
|
101 |
|
|
|
152 |
Operating Margin |
|
64 |
|
|
|
119 |
Capital Investment |
|
64 |
|
|
|
77 |
Operating Margin Net of Related Capital Investment |
|
- |
|
|
|
42 |
Revenues
Price
|
|
|
|
|
|
|
|
|
Three
Months Ended
September 30, 2017 |
|
|
|
May 17
September 30, 2017 |
NGLs
($/bbl) |
|
30.78 |
|
|
|
29.57 |
Light and Medium Oil ($/bbl) |
|
52.54 |
|
|
|
55.64 |
Natural Gas ($/mcf) |
|
1.77 |
|
|
|
2.15 |
Total Oil Equivalent
($/BOE) |
|
17.61 |
|
|
|
19.07 |
Our Deep Basin Assets produce a variety of products from natural gas, condensate, other NGLs (including ethane, propane,
butane and pentane) and light and medium oil.
|
|
|
Cenovus Energy Inc.
Third Quarter 2017 Report |
|
Page 30
Managements Discussion and Analysis |
For the three and nine months ended September 30, 2017, revenues include $13 million and
$19 million, respectively, of processing fee revenue related to our interests in natural gas processing facilities. We do not include processing fee revenue in our per-unit pricing metrics or our
netbacks.
Production Volumes
|
|
|
|
|
|
|
|
|
Three Months Ended
September 30, 2017 |
|
|
|
Nine Months Ended
September 30, 2017 |
Liquids |
|
|
|
|
|
|
NGLs (barrels per day) |
|
26,370 |
|
|
|
13,498 |
Light and Medium Oil (barrels per day) |
|
6,494 |
|
|
|
3,208 |
|
|
32,864 |
|
|
|
16,706 |
Natural Gas (MMcf per day) |
|
495 |
|
|
|
251 |
Total Production (BOE/per day) |
|
115,301 |
|
|
|
58,516 |
Natural Gas Production (percentage of total) |
|
71% |
|
|
|
71% |
Liquids Production (percentage of total) |
|
29% |
|
|
|
29% |
Total production from the date of Acquisition to September 30, 2017 was 116,605 BOE per day, equivalent to 58,516 BOE
per day for the nine months ended September 30, 2017.
Royalties
The Deep Basin Assets are subject to royalty regimes in both Alberta and British Columbia. In Alberta, royalties benefit from a number of different
programs that reduce the royalty rate on natural gas production. Natural gas wells in Alberta also benefit from the Gas Cost Allowance (GCA), which reduces royalties, to account for capital and operating costs incurred to process and
transport the Crowns portion of natural gas production.
Effective January 1, 2017, the Alberta Government released a new Royalty Regime,
Albertas Modernized Royalty Framework (MRF), which applies to all producing wells after January 1, 2017. Under this new framework, Cenovus will pay a five percent pre-payout royalty on
all production until the total revenue from a well equals the drilling and completion cost allowance calculated for each well that meets certain MRF criteria. Subsequently, a higher post-payout royalty rate will apply and will vary based on
product-specific market prices. Once a well reaches a maturity threshold, the royalty rate will drop to better match declining production rates. Wells drilled before January 1, 2017 will be managed under the old framework until 2027 and then
will convert to the MRF.
In British Columbia, royalties also benefit from programs to reduce the rate on natural gas production. British Columbia
applies a GCA, but only on natural gas processed through producer-owned plants. British Columbia also offers a Producer Cost of Service allowance, which reduces the royalty for the processing of the Crowns portion of natural gas production.
For the three and nine months ended September 30, 2017, the effective liquids royalty rate was 11.4 percent. In the third quarter and on a year-to-date basis in 2017, the effective natural gas royalty rate was 3.5 percent and 3.7 percent, respectively.
Expenses
Transportation
For the three and nine months ended September 30, 2017, transportation costs were $1.96 per BOE. Transportation expenses include charges for
the transportation of crude oil, natural gas and NGLs to the sales point.
Operating
Primary drivers of our operating expenses for the third quarter and on a
year-to-date basis related to repairs and maintenance, workforce costs, processing fee expense, and property tax and lease costs. In the third quarter and on a year-to-date basis, operating costs were $9.00 per BOE and $8.95 per BOE, respectively.
Netbacks
|
|
|
|
|
|
|
($/BOE) |
|
Three
Months Ended
September 30, 2017 |
|
|
|
May 17
September 30, 2017 |
|
|
|
|
Sales Price |
|
17.61 |
|
|
|
19.07 |
Royalties |
|
1.28 |
|
|
|
1.34 |
Transportation and Blending |
|
1.96 |
|
|
|
1.96 |
Operating Expenses |
|
9.00 |
|
|
|
8.95 |
Production and Mineral Taxes |
|
0.03 |
|
|
|
0.03 |
Netback |
|
5.34 |
|
|
|
6.79 |
|
|
|
Cenovus Energy Inc.
Third Quarter 2017 Report |
|
Page 31
Managements Discussion and Analysis |
Deep Basin Capital Investment
In the Deep Basin, we are taking a disciplined approach to development activities. In 2017, capital investment is focused on the drilling and completion
of horizontal production wells targeting liquids rich gas within the Deep Basin corridor.
|
|
|
($ millions) |
|
May 17
September 30,
2017 |
|
|
Drilling and Completions |
|
47 |
Facilities |
|
11 |
Other |
|
19 |
Capital Investment (1) |
|
77 |
(1) |
Includes expenditures on PP&E and E&E assets. |
Drilling Activity
|
|
|
(net wells, unless otherwise stated) |
|
May 17
September 30,
2017 |
|
|
Drilled |
|
10 |
Completed |
|
4 |
Tied-in |
|
3 |
Future Capital Investment
Our 2017 Deep Basin capital investment is forecast to be between $160 million and $180 million.
We are taking a disciplined development approach on the Deep Basin Assets through 2017 and anticipate ramping up our activity levels through 2020. We plan
to focus capital investment on a number of drilling opportunities that have the potential to generate strong returns and start to use facilities that are currently underutilized.
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. Deep Basin DD&A for the three and nine months ended September 30, 2017 was $91 million and $136 million,
respectively.
CONVENTIONAL (DISCONTINUED OPERATIONS)
Our divestiture plans for our legacy Conventional assets are well underway. On September 29, 2017, we closed the sale of our Pelican Lake assets,
including the adjacent Grand Rapids project, for gross cash proceeds of $975 million. On September 25, 2017, we announced the sale of our Suffield crude oil and natural gas assets in southern Alberta for gross cash proceeds of
$512 million, plus a DPPA. As at September 30, 2017, the fair value of the DPPA was estimated to be between $5 million and $10 million. On October 19, 2017, we announced the divestiture of our Palliser crude oil and natural
gas operations in southern Alberta for gross cash proceeds of $1.3 billion. Both sales are expected to close in the fourth quarter, subject to customary closing conditions. The sales process for our CO2 enhanced oil recovery project at Weyburn is progressing as planned and we expect to make a further divestiture announcement in the fourth quarter. The established assets in this segment have long
life reserves, stable operations and produce a diversity of crude oil.
Significant developments that impacted our Conventional segment in the third
quarter of 2017 compared with 2016 include:
· |
|
Recording a loss of $603 million on the sale of our Pelican Lake assets and the adjacent Grand Rapids project;
|
· |
|
Our average liquids sales price increasing 13 percent to $49.79 per barrel; |
· |
|
Liquids and natural gas Netbacks, excluding realized risk management activities, of $20.37 per barrel (2016
$20.63 per barrel) and $0.53 per Mcf (2016 $1.25 per Mcf), respectively; |
· |
|
Liquids production averaging 53,697 barrels per day, declining slightly from 2016 primarily due to expected natural
declines, partially offset by an increase in production associated with the tight oil drilling program in southern Alberta; and |
· |
|
Generating Operating Margin net of capital investment of $75 million, a decrease of 32 percent.
|
|
|
|
Cenovus Energy Inc.
Third Quarter 2017 Report |
|
Page 32
Managements Discussion and Analysis |
The third quarter Conventional results include our Suffield and Pelican Lake assets.
Conventional Liquids
Three Months
Ended September 30, 2017 Compared With September 30, 2016
Financial Results
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
($ millions) |
|
2017 |
|
|
|
2016 |
|
|
|
|
Gross Sales |
|
268 |
|
|
|
242 |
Less: Royalties |
|
43 |
|
|
|
32 |
Revenues |
|
225 |
|
|
|
210 |
Expenses |
|
|
|
|
|
|
Transportation and Blending |
|
41 |
|
|
|
40 |
Operating |
|
79 |
|
|
|
65 |
Production and Mineral Taxes |
|
4 |
|
|
|
4 |
(Gain) Loss on Risk Management |
|
5 |
|
|
|
(7) |
Operating Margin |
|
96 |
|
|
|
108 |
Capital Investment |
|
41 |
|
|
|
39 |
Operating Margin Net of Related Capital Investment |
|
55 |
|
|
|
69 |
Operating Margin 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
Price
Our Conventional assets produce a variety of crude oils, ranging from heavy oil, which realizes a price based on the WCS benchmark, to light oil, which
realizes a price closer to the WTI benchmark.
Our liquids sales price averaged $49.79 per barrel in the third quarter of 2017, a 13 percent
increase from 2016, due to higher crude oil benchmark prices, adjusted for applicable differentials, and the narrowing of the WCS-Condensate differential, partially offset by the strengthening of the Canadian
dollar relative to the U.S. dollar. As the cost of condensate decreases relative to the price of blended crude oil, our heavy oil sales price increases. Due to high demand for condensate at Edmonton, we also purchase condensate from U.S. markets. As
such, our average cost of condensate is generally higher than the Edmonton benchmark price due to transportation between market hubs and to field locations. In addition, up to three months may elapse from when we purchase condensate to when we blend
it with our production. In a rising price environment, we expect to see some benefit in our heavy oil sales price as we are using condensate purchased at a lower price earlier in the year.
Production Volumes
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
(barrels per day) |
|
2017 |
|
|
|
Percent Change |
|
|
|
2016 |
|
|
|
|
|
|
Heavy Oil |
|
25,549 |
|
|
|
(9)% |
|
|
|
28,096 |
Light and Medium Oil |
|
26,947 |
|
|
|
6% |
|
|
|
25,311 |
NGLs |
|
1,201 |
|
|
|
12% |
|
|
|
1,074 |
|
|
53,697 |
|
|
|
(1)% |
|
|
|
54,481 |
Total production declined slightly in 2017 compared with 2016 primarily as a result of expected natural declines,
partially offset by an increase in light and medium oil associated with our tight oil drilling program in southern Alberta. We wound down our drilling program early in the third quarter due to the pending sale of these assets.
|
|
|
Cenovus Energy Inc.
Third Quarter 2017 Report |
|
Page 33
Managements Discussion and Analysis |
Condensate
The heavy oil currently produced by Cenovus must be blended with condensate to reduce its thickness in order to transport it to market through pipelines.
Our blending ratios for Conventional heavy oil range between 10 percent and 16 percent. Revenues represent the total value of blended crude oil sold and includes the value of condensate. Consistent with the narrowing of the WCS-Condensate differential in the third quarter of 2017, the proportion of the cost of condensate recovered increased.
Royalties
Conventional liquids royalties increased primarily due to higher royalty rates and an increase in our sales prices, partially offset by a decline in sales
volumes. In the third quarter of 2017, the effective liquids royalty rate for our Conventional properties was 19.0 percent (2016 15.8 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 sales prices. Net profits are a function of sales volumes,
sales prices and allowed operating and capital costs. The Pelican Lake crown royalty calculation was based on net profits in 2017 and 2016.
Expenses
Transportation and Blending
Transportation and blending costs increased slightly in the third quarter of 2017. Transportation charges were higher due to increased costs associated
with optimizing our sales, partially offset by a decline in sales volumes. Blending costs were relatively consistent as higher condensate prices were mostly offset by a decrease in condensate volumes.
Operating
Primary
drivers of our operating expenses in the third quarter of 2017 were workover activities, workforce costs, electricity, property taxes and lease costs, and repairs and maintenance. Operating costs increased 24 percent to $16.02 per barrel
primarily due to:
· |
|
A rise in workover costs, repairs and maintenance, and fluid, waste handling and trucking costs as a result of increased
activity; and |
· |
|
An increase in electricity costs. |
In the third quarter of 2017, production and mineral taxes were consistent with 2016.
Netbacks (1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Heavy Oil |
|
|
|
Light and Medium Oil |
|
|
Three Months Ended September 30, |
($/bbl) |
|
2017 |
|
|
|
2016 |
|
|
|
2017 |
|
|
|
2016 |
Sales Price |
|
48.01 |
|
|
|
40.50 |
|
|
|
51.91 |
|
|
|
48.97 |
Royalties |
|
7.04 |
|
|
|
3.97 |
|
|
|
10.22 |
|
|
|
8.91 |
Transportation and Blending |
|
5.45 |
|
|
|
4.86 |
|
|
|
2.85 |
|
|
|
2.71 |
Operating Expenses |
|
15.50 |
|
|
|
12.43 |
|
|
|
17.19 |
|
|
|
13.94 |
Production and Mineral Taxes |
|
0.01 |
|
|
|
0.01 |
|
|
|
1.54 |
|
|
|
1.48 |
Netback Excluding Realized Risk Management |
|
20.01 |
|
|
|
19.23 |
|
|
|
20.11 |
|
|
|
21.93 |
Realized Risk Management Gain (Loss) |
|
(0.89) |
|
|
|
1.50 |
|
|
|
(1.17) |
|
|
|
1.47 |
Netback Including Realized Risk Management |
|
19.12 |
|
|
|
20.73 |
|
|
|
18.94 |
|
|
|
23.40 |
(1) |
Netbacks reflect our margin on a per-barrel basis of unblended crude oil. |
Risk Management
Risk management activities for the third quarter of 2017 resulted in realized losses of $5 million (2016 realized gains of $7 million),
consistent with average benchmark prices exceeding our contract prices.
|
|
|
Cenovus Energy Inc.
Third Quarter 2017 Report |
|
Page 34
Managements Discussion and Analysis |
Nine Months Ended September 30, 2017 Compared With September 30, 2016
Financial Results
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, |
($ millions) |
|
2017 |
|
|
|
2016 |
|
|
|
|
Gross Sales |
|
840 |
|
|
|
670 |
Less: Royalties |
|
133 |
|
|
|
80 |
Revenues |
|
707 |
|
|
|
590 |
Expenses |
|
|
|
|
|
|
Transportation and Blending |
|
139 |
|
|
|
124 |
Operating |
|
224 |
|
|
|
213 |
Production and Mineral Taxes |
|
13 |
|
|
|
9 |
(Gain) Loss on Risk Management |
|
21 |
|
|
|
(58) |
Operating Margin |
|
310 |
|
|
|
302 |
Capital Investment |
|
173 |
|
|
|
108 |
Operating Margin Net of Related Capital Investment |
|
137 |
|
|
|
194 |
Operating Margin 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
Price
Our average liquids sales price increased 33 percent to $51.03 per barrel consistent with the improvement in crude oil benchmark prices, net of
applicable differentials.
Production Volumes
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, |
(barrels per day) |
|
2017 |
|
|
|
Percent
Change |
|
|
|
2016 |
|
|
|
|
|
|
Heavy Oil |
|
26,466 |
|
|
|
(10)% |
|
|
|
29,276 |
Light and Medium Oil |
|
26,430 |
|
|
|
1% |
|
|
|
26,200 |
NGLs |
|
1,128 |
|
|
|
10% |
|
|
|
1,027 |
|
|
54,024 |
|
|
|
(4)% |
|
|
|
56,503 |
Total production decreased primarily as a result of expected natural declines, partially offset by an increase in
production associated with our tight oil drilling program in southern Alberta. We wound down our drilling program early in the third quarter due to the pending sale of these assets.
Royalties
Royalties increased $53 million primarily due to an increase in our sales prices, higher royalty rates, and lower allowable costs for royalty
purposes at Weyburn and Pelican Lake, partially offset by a reduction in sales volumes. For the nine months ended September 30, 2017, the effective liquids royalty rate for our Conventional properties was 19.2 percent (2016
14.9 percent).
|
|
|
Cenovus Energy Inc.
Third Quarter 2017 Report |
|
Page 35
Managements Discussion and Analysis |
Expenses
Transportation and Blending
Transportation and blending costs increased $15 million, primarily due to a rise in blending costs as a result of higher condensate prices, partially
offset by a decrease in condensate volumes, consistent with lower production. Transportation charges were lower largely due to a decline in sales volumes.
Operating
Primary
drivers of our operating expenses on a year-to-date basis in 2017 were workforce costs, workover activities, electricity, property taxes and lease costs and repairs and
maintenance. Operating expenses increased $1.26 per barrel, to $15.17 per barrel.
The per unit increase was primarily due to lower production
volumes, an increase in workover and repairs and maintenance activities, and higher energy costs. This increase was partially offset by a decrease in chemical costs associated with reduced polymer consumption.
Production and mineral taxes increased on a year-to-date basis due to the
rise in crude oil prices.
Netbacks (1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Heavy Oil
|
|
|
|
Light and Medium Oil |
|
|
Nine Months Ended September 30, |
($/bbl) |
|
2017 |
|
|
|
2016 |
|
|
|
2017 |
|
|
|
2016 |
|
|
|
|
|
|
|
|
Sales Price |
|
47.46 |
|
|
|
34.18 |
|
|
|
54.97 |
|
|
|
43.66 |
Royalties |
|
6.72 |
|
|
|
3.06 |
|
|
|
11.47 |
|
|
|
7.50 |
Transportation and Blending |
|
4.44 |
|
|
|
4.50 |
|
|
|
2.79 |
|
|
|
2.74 |
Operating Expenses |
|
14.30 |
|
|
|
12.94 |
|
|
|
16.68 |
|
|
|
15.52 |
Production and Mineral Taxes |
|
0.01 |
|
|
|
- |
|
|
|
1.77 |
|
|
|
1.15 |
Netback Excluding Realized Risk Management |
|
21.99 |
|
|
|
13.68 |
|
|
|
22.26 |
|
|
|
16.75 |
Realized Risk Management Gain (Loss) |
|
(1.47) |
|
|
|
3.98 |
|
|
|
(1.46) |
|
|
|
3.88 |
Netback Including Realized Risk Management |
|
20.52 |
|
|
|
17.66 |
|
|
|
20.80 |
|
|
|
20.63 |
(1) |
Netbacks reflect our margin on a per-barrel basis of unblended crude oil.
|
Risk Management
Risk management activities for the nine months ended September 30, 2016 resulted in realized losses of $21 million (2016 realized gains
of $58 million), consistent with average benchmark prices exceeding our contract prices.
Conventional Natural Gas
Financial Results
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
Nine Months Ended
September 30, |
($ millions) |
|
2017 |
|
|
|
2016 |
|
|
|
2017 |
|
|
|
2016 |
|
|
|
|
|
|
|
|
Gross Sales |
|
62 |
|
|
|
86 |
|
|
|
247 |
|
|
|
221 |
Less: Royalties |
|
2 |
|
|
|
3 |
|
|
|
12 |
|
|
|
8 |
Revenues |
|
60 |
|
|
|
83 |
|
|
|
235 |
|
|
|
213 |
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transportation and Blending |
|
3 |
|
|
|
4 |
|
|
|
10 |
|
|
|
12 |
Operating |
|
39 |
|
|
|
35 |
|
|
|
117 |
|
|
|
113 |
Production and Mineral Taxes |
|
- |
|
|
|
- |
|
|
|
1 |
|
|
|
- |
(Gain) Loss on Risk Management |
|
(2) |
|
|
|
- |
|
|
|
(2) |
|
|
|
1 |
Operating Margin |
|
20 |
|
|
|
44 |
|
|
|
109 |
|
|
|
87 |
Capital Investment |
|
1 |
|
|
|
2 |
|
|
|
7 |
|
|
|
6 |
Operating Margin Net of Related Capital Investment |
|
19 |
|
|
|
42 |
|
|
|
102 |
|
|
|
81 |
The Operating Margin from natural gas continued to help fund growth opportunities in our Oil Sands and Deep Basin segments.
|
|
|
Cenovus Energy Inc.
Third Quarter 2017 Report |
|
Page 36
Managements Discussion and Analysis |
Three and Nine Months Ended September 30, 2017 Compared With September 30, 2016
Revenues
Price
In the three months ended September 30, 2017, our average natural gas sales price decreased 22 percent to $1.94 per Mcf,
consistent with the decline in the AECO benchmark price. On a year-to-date basis, our average natural gas sales price increased 22 percent to $2.58 per Mcf,
consistent with the rise in the AECO benchmark price.
Production
Production decreased six percent to 350 MMcf per day in the third quarter of 2017. On a
year-to-date basis, production declined eight percent to 351 MMcf per day due to expected natural declines.
Royalties
Royalties decreased
slightly in the third quarter due to lower sales prices and production declines. On a year-to-date basis, royalties increased as a result of higher sales prices,
partially offset by production declines. The average royalty rate in the third quarter and on a year-to-date basis was 5.1 percent (2016
4.5 percent and 4.4 percent, respectively).
Expenses
Transportation
In the three and
nine months ended September 30, 2017, transportation costs declined slightly compared with 2016 primarily due to a decrease in sales volumes.
Operating
Primary drivers of our operating expenses in the three and nine months ended September 30, 2017 were
property taxes and lease costs, workforce costs and repairs and maintenance. Operating expenses increased in the three and nine months ended September 30, 2017 primarily due to an increase in repairs and maintenance.
Risk Management
Risk management activities resulted in realized gains of $2 million in the third quarter and on a year-to-date basis (2016 $nil in the third quarter and realized losses of $1 million on a year-to-date basis),
consistent with our contract prices exceeding average benchmark prices.
Conventional Capital Investment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
Nine Months Ended
September 30, |
($ millions) |
|
2017 |
|
|
|
2016 |
|
|
|
2017 |
|
|
|
2016 |
|
|
|
|
|
|
|
|
Heavy Oil |
|
14 |
|
|
|
11 |
|
|
|
30 |
|
|
|
34 |
Light and Medium Oil |
|
27 |
|
|
|
28 |
|
|
|
143 |
|
|
|
74 |
Natural Gas |
|
1 |
|
|
|
2 |
|
|
|
7 |
|
|
|
6 |
Capital Investment (1) |
|
42 |
|
|
|
41 |
|
|
|
180 |
|
|
|
114 |
(1) |
Includes expenditures on PP&E, E&E assets, and assets held for sale. |
Capital investment for the three and nine months ended September 30, 2017 was primarily related to sustaining capital and the purchase of CO2 at Weyburn. On a year-to-date basis, capital investment also focused on our tight oil drilling opportunities in
southern Alberta. We wound down our drilling program early in the third quarter due to the pending sale of these assets. Capital investment increased compared with 2016 as a result of limited crude oil capital investment activities in 2016 in
response to the low commodity price environment.
Drilling Activity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
September 30, |
(net wells, unless otherwise stated) |
|
|
|
|
|
|
|
|
|
2017 |
|
|
|
2016 |
|
|
|
|
|
|
|
|
Crude Oil |
|
|
|
|
|
|
|
|
|
24 |
|
|
|
1 |
Recompletions |
|
|
|
|
|
|
|
|
|
- |
|
|
|
84 |
Gross Stratigraphic Test Wells |
|
|
|
|
|
|
|
|
|
26 |
|
|
|
27 |
Drilling activity on a year-to-date basis
in 2017 focused on drilling stratigraphic test wells and horizontal production wells for tight oil in southern Alberta.
|
|
|
Cenovus Energy Inc.
Third Quarter 2017 Report |
|
Page 37
Managements Discussion and Analysis |
Future Capital Investment
We updated our 2017 guidance estimates to reflect our recently completed and anticipated divestiture activities. Our revised full-year 2017 Conventional
capital investment guidance is forecast to be between $210 million and $225 million, mainly related to sustaining capital, a decrease of approximately 13 percent from July 26, 2017.
DD&A and Exploration Expense
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.
No DD&A was recorded in the third
quarter of 2017 due to the classification of the Conventional segment as held for sale as required by IFRS. DD&A in 2016 included impairment losses of $210 million and $65 million associated with our Northern Alberta cash-generating
unit (CGU) and Suffield CGU, respectively.
DD&A decreased $687 million on a year-to-date basis primarily due to impairment losses of $445 million recorded in 2016, the decision to divest our conventional assets, and a decline in sales volumes.
REFINING AND MARKETING
Cenovus
is a 50 percent partner in the Wood River and Borger refineries, which are located in the U.S. and operated by our partner, Phillips 66. 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 the Refineries. This segment captures our
marketing and transportation initiatives as well as our crude-by-rail terminal operations located in Bruderheim, Alberta. In the three and nine months ended
September 30, 2017, we loaded an average of 10,542 and 11,166 gross barrels per day, respectively (2016 15,186 and 12,487 gross barrels per day, respectively).
Refinery Operations (1)
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
September 30, |
|
|
|
Nine Months Ended
September 30, |
|
|
2017 |
|
2016 |
|
|
|
2017 |
|
2016 |
|
|
|
|
|
|
Crude Oil Capacity (Mbbls/d) |
|
460 |
|
460 |
|
|
|
460 |
|
460 |
Crude Oil Runs (Mbbls/d) |
|
462 |
|
463 |
|
|
|
439 |
|
452 |
Heavy Crude Oil |
|
213 |
|
241 |
|
|
|
205 |
|
237 |
Light/Medium |
|
249 |
|
222 |
|
|
|
234 |
|
215 |
Refined Products (Mbbls/d) |
|
490 |
|
494 |
|
|
|
467 |
|
479 |
Gasoline |
|
239 |
|
235 |
|
|
|
230 |
|
235 |
Distillate |
|
156 |
|
152 |
|
|
|
147 |
|
148 |
Other |
|
95 |
|
107 |
|
|
|
90 |
|
96 |
Crude Utilization
(percent) |
|
100 |
|
101 |
|
|
|
95 |
|
98 |
(1) |
Represents 100 percent of the Wood River and Borger refinery operations. |
On a 100-percent basis, the Refineries have a total processing capacity of approximately 460,000 gross barrels per
day of crude oil, including processing capability of up to 255,000 gross barrels per day of blended heavy crude oil and 45,000 gross barrels per day of NGLs. The ability to process a wide slate of crude oils allows the Refineries to economically
integrate heavy crude oil production. Processing less expensive crude oil relative to WTI creates a feedstock cost advantage, illustrated by the discount of WCS relative to WTI. 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 optimized at each refinery to maximize economic benefit. Crude utilization represents the percentage of total crude oil processed in the Refineries relative to
the total capacity.
In the third quarter, refined product output declined compared with 2016 primarily due to unplanned maintenance at both
Refineries in 2017. Lower heavy crude oil volumes were processed due to optimization of the total crude input slate as a result of narrowing heavy crude oil differentials.
On a year-to-date basis, crude oil runs and refined product output
decreased compared with 2016 primarily due to the larger scope of the planned turnarounds at both Refineries during the first quarter of 2017 compared with 2016, in addition to unplanned maintenance at both Refineries in 2017. Lower heavy crude oil
volumes were processed due to the planned turnarounds in the first quarter of 2017 and optimization of the total crude input slate.
|
|
|
Cenovus Energy Inc.
Third Quarter 2017 Report |
|
Page 38
Managements Discussion and Analysis |
Financial Results
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
|
|
Nine Months Ended
September 30, |
($ millions) |
|
2017 |
|
|
|
2016 |
|
|
|
2017 |
|
|
|
2016 |
Revenues |
|
2,161 |
|
|
|
2,245 |
|
|
|
7,162 |
|
|
|
5,962 |
Purchased Product |
|
1,782 |
|
|
|
2,004 |
|
|
|
6,295 |
|
|
|
5,144 |
Gross Margin |
|
379 |
|
|
|
241 |
|
|
|
867 |
|
|
|
818 |
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating |
|
168 |
|
|
|
172 |
|
|
|
579 |
|
|
|
557 |
(Gain) Loss on Risk Management |
|
- |
|
|
|
1 |
|
|
|
4 |
|
|
|
23 |
Operating Margin |
|
211 |
|
|
|
68 |
|
|
|
284 |
|
|
|
238 |
Capital Investment |
|
38 |
|
|
|
51 |
|
|
|
124 |
|
|
|
156 |
Operating Margin Net of Related Capital Investment |
|
173 |
|
|
|
17 |
|
|
|
160 |
|
|
|
82 |
Gross Margin
The refining realized crack spread, which is the gross margin on a per barrel basis, is affected by many factors, such as the variety of feedstock crude
oil processed; 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 the Refineries; and the cost of
feedstock. Feedstock costs are valued on a FIFO accounting basis.
In the three months ended September 30, 2017, our gross margin increased
primarily due to higher average market crack spreads and a rise in margins on the sale of our secondary products, such as NGLs, coke, and asphalt, due to higher realized prices. These increases in gross margin were partially offset by:
· |
|
Narrowing heavy crude oil differentials; and |
· |
|
The strengthening of the Canadian dollar relative to the U.S. dollar, which had a negative impact of approximately
$15 million on our gross margin. |
In the nine months ended September 30, 2017, our gross margin rose primarily due to
higher average market crack spreads, and a rise in margins on the sale of our secondary products. These increases in gross margin were partially offset by:
· |
|
Narrowing heavy crude oil differentials; |
· |
|
Lower crude utilization rates; and |
· |
|
The strengthening of the Canadian dollar relative to the U.S. dollar, which had a negative impact of approximately
$9 million on our gross margin. |
In the three and nine months ended September 30, 2017, the costs associated with
Renewable Identification Numbers (RINs) were $81 million and $208 million, respectively (2016 $80 million and $209 million, respectively). The costs of RINs remained relatively consistent as the decrease in
RINs benchmark prices was offset by an increase in the required RINs volume obligation.
Operating Expense
Primary drivers of operating expenses in the third quarter and on a
year-to-date basis of 2017 were labour, maintenance, utilities and supplies. Reported operating expenses were lower in the third quarter compared with 2016 primarily due
to the strengthening of the Canadian dollar relative to the U.S. dollar, partially offset by an increase in labour costs. On a year-to-date basis, operating expenses
increased due to higher utility costs resulting from higher natural gas prices, and an increase in maintenance costs associated with the plant turnarounds in the first quarter of 2017.
Refining and Marketing Capital Investment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
Nine Months Ended September 30, |
($ millions) |
|
2017 |
|
|
|
2016 |
|
|
|
2017 |
|
|
|
2016 |
Wood River Refinery |
|
24 |
|
|
|
33 |
|
|
|
80 |
|
|
|
108 |
Borger Refinery |
|
11 |
|
|
|
16 |
|
|
|
40 |
|
|
|
42 |
Marketing |
|
3 |
|
|
|
2 |
|
|
|
4 |
|
|
|
6 |
|
|
38 |
|
|
|
51 |
|
|
|
124 |
|
|
|
156 |
Capital expenditures in 2017 focused on capital maintenance and reliability work. Capital investment declined in the third
quarter and on a year-to-date basis compared with 2016 primarily due to the completion of work on the debottlenecking project at the Wood River refinery in the third
quarter of 2016.
We updated our 2017 guidance estimates upon further review of our capital program. Our revised full-year 2017 Refining and Marketing
capital investment is forecast to be between $180 million and $200 million, mainly related to capital maintenance and reliability work. Guidance has decreased from July 26, 2017 by approximately five percent to reflect our continued
focus on capital discipline.
|
|
|
Cenovus Energy Inc.
Third Quarter 2017 Report |
|
Page 39
Managements Discussion and Analysis |
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 three to 40 years. The service lives of these assets are reviewed on an annual basis. Refining and Marketing DD&A increased by
$1 million in the third quarter and $5 million on a year-to-date basis, primarily due to the change in the U.S./Canadian dollar exchange rate.
CORPORATE AND ELIMINATIONS
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, power costs, interest rates, and foreign exchange rates, as well as realized risk management gains on interest rate swaps and foreign exchange contracts. In the third quarter of 2017, our risk management activities resulted in
$486 million of unrealized losses (2016 $7 million of unrealized losses). On a year-to-date basis, we incurred $75 million of unrealized risk
management losses (2016 $440 million of unrealized losses). As financial instruments are settled, the realized gains and losses are recorded in the reportable segment to which the derivative instrument relates. On a year-to-date basis, we realized a $142 million risk management gain on foreign exchange contracts primarily due to hedging activity undertaken to support the Acquisition.
The Corporate and Eliminations segment also includes Cenovus-wide costs for general and administrative, finance costs, interest income, foreign
exchange (gain) loss, revaluation (gain), transaction costs, re-measurement of the contingent payment, research costs, (gain) loss on divestiture of assets, and other (income) loss.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
Nine Months Ended September 30, |
($ millions) |
|
2017 |
|
|
|
2016 |
|
|
|
2017 |
|
|
|
2016 |
|
|
|
|
|
|
|
|
General and Administrative |
|
116 |
|
|
|
71 |
|
|
|
217 |
|
|
|
225 |
Finance Costs |
|
191 |
|
|
|
97 |
|
|
|
458 |
|
|
|
292 |
Interest Income |
|
(32) |
|
|
|
(27) |
|
|
|
(59) |
|
|
|
(45) |
Foreign Exchange (Gain) Loss, Net |
|
(350) |
|
|
|
45 |
|
|
|
(836) |
|
|
|
(338) |
Revaluation (Gain) |
|
- |
|
|
|
- |
|
|
|
(2,524) |
|
|
|
- |
Transaction Costs |
|
1 |
|
|
|
- |
|
|
|
56 |
|
|
|
- |
Re-measurement of the Contingent Payment |
|
(43) |
|
|
|
- |
|
|
|
(109) |
|
|
|
- |
Research Costs |
|
6 |
|
|
|
5 |
|
|
|
15 |
|
|
|
30 |
(Gain) Loss on Divestiture of Assets |
|
(1) |
|
|
|
5 |
|
|
|
- |
|
|
|
6 |
Other (Income) Loss, Net |
|
(2) |
|
|
|
5 |
|
|
|
(4) |
|
|
|
7 |
|
|
(114) |
|
|
|
201 |
|
|
|
(2,786) |
|
|
|
177 |
Expenses
General and Administrative
Primary drivers of our general and administrative expenses in the third quarter of 2017 were workforce costs, long-term incentives and office rent.
General and administrative expenses increased by $45 million in the third quarter of 2017 compared with 2016 primarily due to $18 million of costs related to the transitional services provided by ConocoPhillips, a $12 million increase
in long-term employee incentives costs related to an increase in our share price, and a $10 million increase in workforce costs primarily due to the Acquisition.
On a year-to-date basis, primary drivers of our general and administrative
expenses were workforce costs and office rent. In 2017, general and administrative expenses decreased by $8 million compared with 2016 due to:
· |
|
Lower long-term employee incentive costs related to a drop in our share price; |
· |
|
A non-cash expense of $7 million for certain Calgary office space in excess
of Cenovuss current and near-term requirements, compared with $31 million in 2016; and |
· |
|
Lower information technology costs due to process improvements. |
These decreases were partially offset by approximately $28 million of transitional services provided by ConocoPhillips. Under the purchase and sales
agreement, Cenovus and ConocoPhillips agreed to certain transitional services where ConocoPhillips will provide certain day-to-day services required by Cenovus for a
period of approximately nine months. These transactions are in the normal course of operations and are measured at the exchange amounts.
Finance Costs
Finance costs include interest expense on our long-term debt and short-term borrowings as well as the
unwinding of the discount on decommissioning liabilities. In the third quarter and on a year-to-date basis, finance costs increased by $94 million and
$166 million, respectively, primarily due to costs associated with additional debt incurred to finance the Acquisition, including US$2.9 billion of senior unsecured notes, $3.6 billion borrowed under a committed Bridge Facility and
borrowings through our existing committed credit facility. The first tranche and a
|
|
|
Cenovus Energy Inc.
Third Quarter 2017 Report |
|
Page 40
Managements Discussion and Analysis |
portion of the second tranche of the committed Bridge Facility were repaid on September 29, 2017 with proceeds from the sale of our Pelican Lake assets and the adjacent Grand Rapids project.
As at September 30, 2017, $2.65 billion remains outstanding on the committed Bridge Facility. As at September 30, 2017, no amounts were drawn on the existing committed credit facility.
The weighted average interest rate on outstanding debt for the three and nine months ended September 30, 2017 was 4.7 percent and
4.9 percent, respectively (2016 5.3 percent).
Foreign Exchange
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
|
|
|
|
Nine Months Ended
September 30, |
($ millions) |
|
2017 |
|
|
|
2016 |
|
|
|
|
|
2017 |
|
|
|
2016 |
|
|
|
|
|
|
|
|
|
Unrealized Foreign Exchange (Gain) Loss |
|
(440) |
|
|
|
50 |
|
|
|
|
|
(908) |
|
|
|
(341) |
Realized Foreign Exchange (Gain) Loss |
|
90 |
|
|
|
(5) |
|
|
|
|
|
72 |
|
|
|
3 |
|
|
(350) |
|
|
|
45 |
|
|
|
|
|
(836) |
|
|
|
(338) |
In the third quarter and on a year-to-date
basis in 2017, unrealized foreign exchange gains resulted primarily from the translation of our U.S. dollar denominated debt. The Canadian dollar relative to the U.S. dollar at September 30, 2017, strengthened by four percent and eight
percent respectively, in comparison to June 30, 2017 and December 31, 2016. On a year-to-date basis, unrealized foreign exchange gains also resulted from the
translation of U.S. cash that was accumulated leading up to the Acquisition.
In the third quarter and on a year-to-date basis in 2017, realized foreign exchange losses primarily resulted from an increase in the number of sales contracts denominated in U.S. dollars.
Revaluation Gain
Prior to the Acquisition, our 50 percent interest in FCCL was jointly controlled with ConocoPhillips and met the definition of a joint operation
under IFRS 11, Joint Arrangements and as such Cenovus recognized its share of the assets, liabilities, revenues and expenses in its consolidated results. Subsequent to the Acquisition, we control FCCL, as defined under IFRS 10,
Consolidated Financial Statements and accordingly, FCCL has been consolidated. As required by IFRS 3 when control is achieved in stages, the previously held interest in FCCL was
re-measured to its fair value of $12.3 billion and a non-cash revaluation gain of $2.5 billion ($1.8 billion,
after-tax) was recorded in net earnings in the second quarter of 2017.
Transaction
Costs
On a year-to-date basis in 2017, we expensed
$56 million of transaction costs related to the Acquisition.
Re-measurement of
Contingent Payment
Related to oil sands production, Cenovus has agreed to make quarterly payments to ConocoPhillips during the five years
subsequent to the closing date of the Acquisition for quarters in which the average WCS crude oil price exceeds $52 per barrel during the quarter. The quarterly payment will be $6 million for each dollar that the WCS price exceeds $52 per
barrel. There are no maximum payment terms. The calculation includes an adjustment mechanism related to certain significant production outages at Foster Creek and Christina Lake, which may reduce the amount of a contingent payment. As production
capacity increases with future expansions, the percentage of upside available to Cenovus will increase further.
The contingent payment is accounted
for as a financial option. The fair value of $361 million on May 17, 2017 was estimated by calculating the present value of the future expected cash flows using an option pricing model. The contingent payment is subsequently re-measured at fair value at each reporting date with changes in fair value recognized in net earnings. At September 30, 2017, the contingent payment was valued at $252 million. In the three and nine
months ended September 30, 2017, there was a re-measurement gain of $43 million and $109 million, respectively. WCS in the third quarter of 2017 averaged less than $52 per barrel, therefore no
amount was payable.
Average WCS forward pricing for the remaining term of the contingent payment is US$35.51 or C$44.28 per barrel. Estimated
quarterly WCS forward prices for the remaining term of the agreement range between approximately C$42.50 per barrel and C$48.60 per barrel.
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 the third quarter was $15 million (2016 $14 million) and $47 million on a
year-to-date basis (2016 $50 million).
|
|
|
Cenovus Energy Inc.
Third Quarter 2017 Report |
|
Page 41
Managements Discussion and Analysis |
Income Tax
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
Nine Months Ended
September 30, |
($ millions) |
|
2017 |
|
|
|
2016 |
|
|
|
2017 |
|
|
|
2016 |
Current Tax |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada |
|
(23) |
|
|
|
(71) |
|
|
|
(232) |
|
|
|
(187) |
United States |
|
(39) |
|
|
|
- |
|
|
|
(40) |
|
|
|
1 |
Total Current Tax Expense (Recovery) |
|
(62) |
|
|
|
(71) |
|
|
|
(272) |
|
|
|
(186) |
Deferred Tax Expense (Recovery) |
|
(48) |
|
|
|
5 |
|
|
|
893 |
|
|
|
(91) |
Tax Expense (Recovery) From Continuing Operations |
|
(110) |
|
|
|
(66) |
|
|
|
621 |
|
|
|
(277) |
The following table reconciles income taxes calculated at the Canadian statutory rate with the recorded income taxes:
|
|
|
|
|
|
|
|
|
Nine Months Ended
September 30, |
($ millions) |
|
2017 |
|
|
|
2016 |
Earnings (Loss) From Continuing
Operations Before Income Tax |
|
3,701 |
|
|
|
(527) |
Canadian Statutory Rate |
|
27.0% |
|
|
|
27.0% |
Expected Income Tax (Recovery) |
|
999 |
|
|
|
(142) |
Effect of Taxes Resulting From: |
|
|
|
|
|
|
Foreign Tax Rate Differential |
|
(31) |
|
|
|
(38) |
Non-Taxable Capital (Gains) Losses |
|
(148) |
|
|
|
(46) |
Non-Recognition of Capital (Gains) Losses |
|
(121) |
|
|
|
(46) |
Adjustments Arising From Prior Year Tax Filings |
|
(36) |
|
|
|
(48) |
Recognition of Previously Unrecognized Capital Losses |
|
(65) |
|
|
|
- |
Non-Deductible Expenses |
|
3 |
|
|
|
6 |
Other |
|
20 |
|
|
|
37 |
Total Expense (Recovery) From
Continuing Operations |
|
621 |
|
|
|
(277) |
Effective Tax Rate |
|
16.8% |
|
|
|
52.6% |
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 the three and nine months ended
September 30, 2017, a current tax recovery was recorded on continuing operations due to the carry back of current and prior year losses and an adjustment related to prior years. In the third quarter, we recorded a deferred tax recovery as
compared to an expense in 2016 on continuing operations. On a year-to-date basis, a deferred tax expense was recorded in 2017 compared with a recovery in 2016 on
continuing operations due to the revaluation gain of our pre-existing interest in connection with the Acquisition.
In the three and nine months ended September 30, 2017, we recorded an income tax expense of $31 million and $51 million, respectively,
related to discontinued operations (2016 $89 million and $176 million income tax recovery, respectively). The loss on discontinuance includes a $163 million deferred tax recovery.
Our effective tax rate is a function of the relationship between total tax expense (recovery) and the amount of earnings (loss) before income taxes. The
effective tax rate differs from the statutory tax rate as it reflects higher U.S. tax rates, non-taxable foreign exchange (gains) losses, adjustments for changes in tax rates and other tax legislation,
adjustments to the tax basis of the refining assets, variations in the estimate of reserves, differences between the provision and the actual amounts subsequently reported on the tax returns, and other permanent differences. Our effective tax rate
differs from the statutory tax rate due to $715 million of unrealized non-taxable foreign exchange gains.
|
|
|
Cenovus Energy Inc.
Third Quarter 2017 Report |
|
Page 42
Managements Discussion and Analysis |
LIQUIDITY AND CAPITAL RESOURCES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
Nine Months Ended
September 30, |
($ millions) |
|
2017 |
|
|
|
2016 |
|
|
|
2017 |
|
|
|
2016 |
|
|
|
|
|
|
|
|
Cash From (Used In) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Activities |
|
592 |
|
|
|
310 |
|
|
|
2,159 |
|
|
|
697 |
Investing Activities |
|
512 |
|
|
|
(196) |
|
|
|
(14,653) |
|
|
|
(835) |
Net Cash Provided (Used) Before Financing Activities |
|
1,104 |
|
|
|
114 |
|
|
|
(12,494) |
|
|
|
(138) |
Financing Activities |
|
(1,009) |
|
|
|
(41) |
|
|
|
9,227 |
|
|
|
(125) |
Foreign Exchange Gain (Loss) on Cash and Cash Equivalents Held in Foreign Currency |
|
48 |
|
|
|
(3) |
|
|
|
179 |
|
|
|
8 |
Increase (Decrease) in Cash and Cash Equivalents |
|
143 |
|
|
|
70 |
|
|
|
(3,088) |
|
|
|
(255) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2017 |
|
|
|
December 31, 2016 |
|
|
|
|
|
|
|
|
Cash and Cash Equivalents |
|
|
|
|
|
|
|
|
|
632 |
|
|
|
3,720 |
Committed and Undrawn Credit Facilities |
|
|
|
|
|
|
|
|
|
4,500 |
|
|
|
4,000 |
Cash From (Used In) Operating Activities
Cash from operating activities increased for the three and nine months ended September 30, 2017 mainly due to higher Operating Margin, as discussed
in the Financial Results section of this MD&A. Excluding risk management assets and liabilities, assets and liabilities held for sale and the current portion of the contingent payment we had working capital of $1,302 million at
September 30, 2017 compared with $4,423 million at December 31, 2016. The decrease in working capital was primarily due to the Acquisition.
We anticipate that we will continue to meet our payment obligations as they come due.
Cash From (Used In) Investing Activities
In the third quarter of 2017, cash from investing activities was primarily due to cash proceeds from the divestiture of our Pelican Lake assets and the
adjacent Grand Rapids project, partially offset by an increase in capital investment. In 2016, capital investment was limited due to spending reductions in response to the low commodity price environment.
On a year-to-date basis, the increase in cash used in investing activities
was primarily due to the Acquisition and a rise in capital investment, partially offset by proceeds on the divestiture of our Pelican Lake assets and the adjacent Grand Rapids project. In 2016, capital investment was limited due to spending
reductions in response to the low commodity price environment.
Cash From (Used In) Financing Activities
Cash used in financing activities increased in the third quarter of 2017 primarily related to the repayment of the first tranche and a portion of the
second tranche of the committed Bridge Facility. On a year-to-date basis, the increase in cash from financing activities was primarily due to the issuance of debt and
common shares to help finance the Acquisition, partially offset by the repayment of a portion of the committed Bridge Facility.
Total debt as at
September 30, 2017 was $12,094 million (December 31, 2016 $6,332 million), which includes $9,547 million of U.S. denominated senior unsecured notes with no principal payments due until October 15, 2019 (US$1.3
billion) and $2.65 billion under a committed Bridge Facility, both amounts are partially offset by debt discount and transaction costs. The $5,762 million increase in total debt is primarily due to Acquisition financing.
As at September 30, 2017, we were in compliance with all of the terms of our debt agreements.
Senior Unsecured Notes
In connection with the Acquisition, on April 7, 2017, we completed an offering in the U.S. for US$2.9 billion of senior unsecured notes issued
in three tranches, US$1.2 billion 4.25 percent senior unsecured notes due April 2027, US$700 million 5.25 percent senior unsecured notes due June 2037, and US$1.0 billion 5.40 percent senior unsecured notes due
June 2047 (collectively, the 2017 Notes). In connection with the offering of the 2017 Notes, we agreed to make an exchange offer (the Exchange Offering) for the 2017 Notes whereby the holders will be entitled to exchange the
2017 Notes for new notes with the same terms and provisions, except that the new notes will not be subject to transfer restrictions.
|
|
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Cenovus Energy Inc.
Third Quarter 2017 Report |
|
Page 43
Managements Discussion and Analysis |
Base Shelf Prospectus
On October 10, 2017, we filed a base shelf prospectus that allows us to offer, from time to time, up to US$7.5 billion, or the equivalent in
other currencies, of debt securities, common shares, preferred shares, subscription receipts, warrants, share purchase contracts and units in Canada, the U.S. and elsewhere, where permitted by law. The base shelf prospectus also allows us to conduct
the Exchange Offering and ConocoPhillips to offer, should they so choose from time to time, the common shares they acquired in connection with the Acquisition. The base shelf prospectus will expire in November 2019 and replaces our
US$5.0 billion base shelf prospectus, which would have expired in March 2018. Offerings under the base shelf prospectus are subject to market conditions.
Committed Bridge Facility
On May 17, 2017, concurrent with the close of the Acquisition, we borrowed $3.6 billion under a committed Bridge Facility. The Bridge Facility
consisted of a $0.9 billion tranche maturing on May 17, 2018, a $1.8 billion tranche maturing on November 17, 2018, and a $0.9 billion tranche maturing on May 17, 2019. On September 29, 2017, the first
tranche and a portion of the second tranche were repaid resulting in $2.65 billion outstanding as at September 30, 2017. We expect to repay the remainder of the committed Bridge Facility with proceeds from the announced divestitures and
further planned divestitures.
Common Shares
In connection with the Acquisition, on April 6, 2017, Cenovus closed a Bought-Deal Common Share Offering for 187.5 million common shares for
gross proceeds of $3.0 billion.
Dividends
In the three and nine months ended September 30, 2017, we paid dividends of $0.05 per share or $62 million and $0.15 per share or $164 million,
respectively (2016 $0.05 per share or $41 million and $0.15 per share or $124 million, respectively). The declaration of dividends is at the sole discretion of the Board and is considered quarterly.
Available Sources of Liquidity
We expect cash flows from our liquids, natural gas and refining operations to fund a portion of our cash requirements. Any potential shortfalls may be
required to be funded through prudent use of our balance sheet capacity, management of our asset portfolio and other corporate and financial opportunities that may be available to us. We remain committed to maintaining our investment grade credit
ratings at S&P Global Ratings, DBRS Limited, and Fitch Ratings.
The following sources of liquidity are available at September 30, 2017:
|
|
|
|
|
|
|
($ millions) |
|
Term |
|
|
|
Amount |
|
|
|
|
Cash and Cash Equivalents |
|
Not applicable |
|
|
|
632 |
Committed Credit Facility Tranche A |
|
November 2021 |
|
|
|
3,300 |
Committed Credit Facility Tranche B |
|
November 2020 |
|
|
|
1,200 |
Committed Credit Facility
On April 28, 2017, we amended our existing committed credit facility to increase the capacity of the facility by $0.5 billion to
$4.5 billion and to extend the maturity dates. The committed credit facility consists of a $1.2 billion tranche maturing on November 30, 2020 and $3.3 billion tranche maturing on November 30, 2021. As of September 30,
2017, we had $4.5 billion available under 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.
See below for the Debt to Capitalization ratio used by
Cenovus to monitor our capital structure.
Financial Metrics
We monitor our capital structure and financing requirements using, among other things, non-GAAP financial measures
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 net earnings before finance costs, interest income, income tax expense, DD&A, goodwill impairments, asset impairments and reversals, unrealized gains (losses) on
risk management, foreign exchange gains (losses), revaluation gain, re-measurement of contingent payment, gains (losses) on divestiture of assets, loss from discontinuance, and other income (loss), net,
calculated on a trailing 12-month basis. These measures are used to steward our overall debt position and as measures of our overall financial strength.
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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.
|
|
|
|
|
|
|
|
|
September 30, |
|
|
|
December 31, |
As at |
|
2017 |
|
|
|
2016 |
|
|
|
|
Net Debt to Capitalization (1) (2) |
|
37% |
|
|
|
18% |
Debt to Capitalization |
|
38% |
|
|
|
35% |
Net Debt to Adjusted EBITDA (1) |
|
4.1x |
|
|
|
1.9x |
Debt to Adjusted EBITDA |
|
4.3x |
|
|
|
4.5x |
(1) |
Net Debt is defined as Debt net of cash and cash equivalents. |
(2) |
Net Debt to Capitalization is defined as Net Debt divided by Net Debt plus Shareholders Equity.
|
Debt to Capitalization increased as a result of the higher long-term debt balance, related to the Acquisition, partially offset
by the increase in Shareholders Equity and the strengthening of the Canadian dollar relative to the U.S. dollar. Debt to Adjusted EBITDA decreased as a result of a higher Adjusted EBITDA from an increase in commodity prices and the rise in
sales volumes as a result of the Acquisition, partially offset by a higher long-term debt balance. We are intently focused on completing divestitures of our legacy Conventional assets in order to deleverage our balance sheet.
As at September 30, 2017, Cenovuss Debt to Adjusted EBITDA and Net Debt to Adjusted EBITDA are 4.3x and 4.1x, respectively. These ratios are
well outside our target range. However, it is important to note that Adjusted EBITDA is calculated on a rolling twelve month basis and as such, only includes the financial results from the Deep Basin Assets and the additional 50 percent of FCCL
for the period May 17, 2017 to September 30, 2017. Debt and Net Debt are as at September 30, 2017; therefore, the ratios are fully burdened by the debt issued to finance the Acquisition. If Adjusted EBITDA reflected a full twelve
months of earnings from the acquired assets, Cenovuss Debt and Net Debt to Adjusted EBITDA ratios would be substantially lower.
Additional
information regarding our financial measures and capital structure can be found in the notes to the December 31, 2016 Consolidated Financial Statements and the interim Consolidated Financial Statements.
Share Capital and Stock-Based Compensation Plans
As part of our long-term incentive program, Cenovus has an employee Stock Option Plan as well as a Performance Share Unit (PSU) Plan, a
Restricted Share Unit (RSU) Plan and two Deferred Share Unit (DSU) Plans. Certain directors, officers or employees chose prior to December 31, 2016 to convert a portion of their remuneration, paid in the first quarter of
2017, into DSUs. The election for any particular year is irrevocable. DSUs may not be redeemed until departure. Directors also received an annual grant of DSUs.
Refer to Note 21 of the interim Consolidated Financial Statements for more details on our Stock Option Plan and our PSU, RSU and DSU Plans.
|
|
|
|
|
|
|
As at September 30, 2017 |
|
Units
Outstanding (thousands) |
|
|
|
Units
Exercisable (thousands) |
|
|
|
|
Common Shares |
|
1,228,790 |
|
|
|
N/A |
Stock Options |
|
42,864 |
|
|
|
36,326 |
Other Stock-Based Compensation Plans |
|
15,537 |
|
|
|
1,633 |
In connection with the Acquisition, Cenovus closed a Bought-Deal Common Share financing on April 6, 2017 for
187.5 million common shares, raising gross proceeds of $3.0 billion ($2.9 billion net of $101 million of share issuance costs).
In addition, we issued 208 million common shares to ConocoPhillips on May 17, 2017 as partial consideration for the Acquisition. In relation to
the share consideration, Cenovus and ConocoPhillips entered into an investor agreement, and a registration rights agreement which, among other things, restricts ConocoPhillips from selling or hedging its Cenovus common shares until November 17,
2017. ConocoPhillips is also restricted from nominating new members to Cenovuss Board of Directors and must vote its Cenovus common shares in accordance with Managements recommendations or abstain from voting until such time
ConocoPhillips owns 3.5 percent or less of the outstanding common shares of Cenovus.
Contractual Obligations and
Commitments
Cenovus has obligations for goods and services that were entered into in the normal course of business. Obligations are
primarily related to demand charges on firm transportation agreements, operating leases on buildings, our risk management program and an obligation to fund our defined benefit pension and other post-employment benefit plans. Obligations that have
original maturities of less than one year are excluded. For further information, see the notes to the December 31, 2016 Consolidated Financial Statements.
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As at September 30, 2017, total commitments were $20.7 billion, of which $17.2 billion were
for various transportation commitments. During the nine months ended September 30, 2017, our transportation commitments decreased by $9.1 billion, primarily due to our withdrawal from certain transportation initiatives, including the
cancellation of the Energy East Pipeline, and use of contracts, partially offset by new firm transportation agreements. In relation to the Acquisition, we assumed $3.7 billion primarily consisting of transportation commitments on various
pipelines. Transportation commitments include $7.5 billion that are subject to regulatory approval or have been approved but are not yet in service (December 31, 2016 $19.2 billion). Terms are up to 20 years subsequent to the date of
commencement and should help align our future transportation requirements with our anticipated production growth.
As at September 30, 2017,
there were outstanding letters of credit aggregating $257 million issued as security for performance under certain contracts (December 31, 2016 $258 million).
Legal Proceedings
We are involved in a limited number of legal claims associated with the normal course of operations. We believe that any liabilities that might arise from
such matters, to the extent not provided for, are not likely to have a material effect on our interim Consolidated Financial Statements.
Contingent Payment
In connection
with the Acquisition and related to oil sands production, we agreed to make quarterly payments to ConocoPhillips during the five years subsequent to May 17, 2017 for quarters in which the average WCS crude oil price exceeds $52 per barrel
during the quarter. As at September 30, 2017, the estimated fair value of the contingent payment was $252 million. WCS in the third quarter of 2017 averaged less than $52 per barrel; therefore, no amount was payable. The calculation
includes an adjustment mechanism related to certain significant production outages at Foster Creek and Christina Lake, which may reduce the amount of a contingent payment. As production capacity increases with future expansions, the percentage of
upside available to Cenovus will increase further.
See the Corporate and Eliminations section of this MD&A for more details.
RISK MANAGEMENT
For a full understanding of the risks that impact Cenovus, the following discussion should be read in conjunction with the Risk Management section of our
2016 annual MD&A and the first and second quarter 2017 MD&A. In addition, 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, 2016.
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. Actively managing these risks improves our ability to effectively execute our business strategy. We continue to be exposed to the risks identified in
our 2016 annual MD&A, the first and second quarter 2017 MD&A and our AIF.
The following provides an update on our risks related to commodity
prices, risks related to the Acquisition, and risks related to asset divestitures.
Commodity Price Risk
Fluctuations in commodity prices and refined product prices impact our financial condition, results of operations, cash flows, growth, access to capital
and cost of borrowing.
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 23 and 24 to the interim Consolidated Financial Statements.
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 we are unable to fulfill our delivery obligations related to the underlying physical transaction. Financial instruments may
limit the benefit to Cenovus if commodity prices increase. These risks are minimized through hedging limits that are reviewed annually by the Board, as required by our Market Risk Mitigation Policy.
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Managements Discussion and Analysis |
Impact of Financial Risk Management Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
|
2017 |
|
|
|
2016 |
($ millions) |
|
Realized |
|
Unrealized |
|
Total |
|
|
|
Realized |
|
Unrealized |
|
Total |
|
|
|
|
|
|
|
|
Crude Oil |
|
9 |
|
483 |
|
492 |
|
|
|
(32) |
|
(5) |
|
(37) |
Refining |
|
- |
|
2 |
|
2 |
|
|
|
1 |
|
- |
|
1 |
Power |
|
- |
|
- |
|
- |
|
|
|
(3) |
|
- |
|
(3) |
Interest Rate |
|
- |
|
1 |
|
1 |
|
|
|
- |
|
12 |
|
12 |
Foreign Exchange |
|
1 |
|
- |
|
1 |
|
|
|
- |
|
- |
|
- |
(Gain) Loss on Risk Management (1) |
|
10 |
|
486 |
|
496 |
|
|
|
(34) |
|
7 |
|
(27) |
Income Tax Expense (Recovery) |
|
(18) |
|
(132) |
|
(150) |
|
|
|
9 |
|
(2) |
|
7 |
(Gain) Loss on Risk Management, After Tax |
|
(8) |
|
354 |
|
346 |
|
|
|
(25) |
|
5 |
|
(20) |
(1) |
Excludes $3 million of realized risk management losses on contracts from our Conventional segment (2016
$7 million realized risk management gains), which has been classified as a discontinued operation. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, |
|
|
2017 |
|
|
|
2016 |
($ millions) |
|
Realized |
|
Unrealized |
|
Total |
|
|
|
Realized |
|
Unrealized |
|
Total |
|
|
|
|
|
|
|
|
Crude Oil |
|
72 |
|
66 |
|
138 |
|
|
|
(138) |
|
359 |
|
221 |
Refining |
|
4 |
|
(1) |
|
3 |
|
|
|
(4) |
|
4 |
|
- |
Power |
|
- |
|
- |
|
- |
|
|
|
- |
|
(14) |
|
(14) |
Interest Rate |
|
- |
|
10 |
|
10 |
|
|
|
- |
|
91 |
|
91 |
Foreign Exchange |
|
(142) |
|
- |
|
(142) |
|
|
|
- |
|
- |
|
- |
(Gain) Loss on Risk Management (2) |
|
(66) |
|
75 |
|
9 |
|
|
|
(142) |
|
440 |
|
298 |
Income Tax Expense (Recovery) |
|
- |
|
(20) |
|
(20) |
|
|
|
37 |
|
(120) |
|
(83) |
(Gain) Loss on Risk Management, After Tax |
|
(66) |
|
55 |
|
(11) |
|
|
|
(105) |
|
320 |
|
215 |
(2) |
Excludes $19 million of realized risk management losses on contracts from our Conventional segment (2016
$57 million realized risk management gains), which has been classified as a discontinued operation. |
In the third quarter
of 2017 and on a year-to-date basis, we incurred realized losses on crude oil risk management activities, consistent with average benchmark prices exceeding our contract
prices. On a year-to-date basis, we incurred realized gains on foreign exchange contracts undertaken to support the Acquisition. Unrealized losses were recorded on our
crude oil financial instruments in the three and nine months ended September 30, 2017 primarily due to the realization of settled positions and changes in benchmark prices.
Risks Related to the Acquisition and Asset Divestitures
Unexpected Costs or Liabilities Related to the Acquisition
Acquisitions of crude oil and natural gas properties are based largely on engineering, environmental and economic assessments made by the acquiror,
independent engineers and consultants. These assessments include a series of assumptions regarding such factors as recoverability and marketability of crude oil and natural gas, environmental restrictions and prohibitions regarding releases and
emissions of various substances, future prices of crude oil and natural gas and operating costs, future capital expenditures and royalties and other government levies which will be imposed over the producing life of the reserves. Many of these
factors are subject to change and are beyond our control. All such assessments involve a measure of geologic, engineering, environmental and regulatory uncertainty that could result in lower production and reserves or higher operating or capital
expenditures than anticipated.
Although we conducted title and environmental reviews in respect of the Deep Basin Assets, such reviews cannot
guarantee that any unforeseen defects in the chain of title will not arise to defeat our title to certain assets or that environmental defects or deficiencies do not exist.
In connection with the Acquisition, there may be liabilities that we failed to discover or were unable to quantify in our due diligence conducted prior to
the execution of the Acquisition Agreement and we may not be indemnified for some or all of these liabilities. The discovery or quantification of any material liabilities could have a material adverse effect on our business, financial condition or
future prospects. In addition, the Acquisition Agreement limits the amount for which we are indemnified, such that liabilities in respect of the Acquisition may be greater than the amounts for which we are indemnified under the Acquisition
Agreement.
Realization of Acquisition Benefits
We believe that the Acquisition will provide a number of benefits to Cenovus. However, there is a risk that some or all of the expected benefits of the
Acquisition may fail to materialize, may cost more to achieve or may not occur within the time periods that we anticipate. The realization of such benefits may be affected by a number of factors, many of which are beyond our control.
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Amount of Contingent Payments
In connection with the Acquisition, we have agreed to make contingent payments under certain circumstances. The amount of contingent payments will vary
depending on the Canadian dollar WCS price from time to time during the five year period following the closing of the Acquisition, and such payments may be significant. In addition, in the event that such payments are made, this could have an
adverse impact on our reported results and other metrics.
Significant Transaction and Related Costs
We expect to incur a number of costs associated with completing the Acquisition, integrating the Deep Basin Assets and completing the targeted asset
sales. The majority of such costs will consist of acquisition, facilities and systems consolidation and employment-related costs. Additional unanticipated costs may be incurred in the integration of the assets to be acquired under the Acquisition
(collectively, the Acquired Assets) into our business and completing the targeted asset sales.
Operational
and Reserves and Resources Risks Relating to the Acquired Assets
The risk factors set forth in our AIF relating to the crude oil and
natural gas business, environmental matters and the operations and reserves and resources of Cenovus apply equally in respect of the Acquired Assets. In particular, the reserves, resources and recovery information contained in the reserves and
resources reports in respect of the Acquired Assets is only an estimate and the actual production from and ultimate reserves of those properties may be greater or less than the estimates contained in such reports.
Risk of Default in the Repayment of Borrowings under the Credit Facilities
We have incurred material indebtedness under our committed Bridge Facility. We intend to repay borrowings under the committed Bridge Facility through the
sale of certain of our assets. We may not be able to sell such assets in the time period we estimate, or for prices we expect to realize from such sales. If we are unable to sell such assets on the terms that we expect to receive, or at all, our
ability to repay borrowings under the committed Bridge Facility as anticipated could be adversely affected. In the event we are unable to refinance borrowings we incur under our committed Bridge Facility in the manner intended, we may be required to
utilize other sources of liquidity including cash on hand, cash from operating activities or borrowings under our existing committed credit facility to the extent of any availability thereunder. We may also be required to seek extensions to or
modifications of the terms of our existing committed credit facility or committed Bridge Facility in order to defer the maturity dates of borrowings incurred thereunder. In recent years, depressed prices for crude oil and natural gas have materially
affected the operating and financial performance of borrowers in the energy sector which has at times resulted in the curtailment of the availability of credit from lenders, and an unwillingness to provide borrowers with desired extensions to, or
other modifications of, repayment terms. As a result, depending on crude oil and natural gas and credit market conditions at the time when borrowings under our existing committed credit facility or committed Bridge Facility are due for repayment,
and our own financial performance at that time, we may be unable to obtain extensions or modifications of the terms of our existing committed credit facility or committed Bridge Facility on terms satisfactory to us, or at all, which could result in
us defaulting on our repayment obligations under our existing committed credit facility or committed Bridge Facility and being subject to various remedies available to the lenders thereunder including remedies available under applicable bankruptcy
and insolvency legislation.
Increased Indebtedness
In order to finance the Acquisition, we borrowed $3.6 billion on a committed Bridge Facility and issued US$2.9 billion in senior unsecured
notes. Such borrowings represent a significant increase in Cenovuss consolidated indebtedness. Such additional indebtedness increased Cenovuss interest expense and debt service obligations and may have a negative effect on Cenovuss
results of operations. On September 29, 2017, we completed the sale of our Pelican Lake assets and the adjacent Grand Rapids project, the first of a series of anticipated divestitures, for gross cash proceeds of $975 million. Net cash
proceeds from the sale were applied against the $3.6 billion committed Bridge Facility. As at September 30, 2017, we had $2.65 billion outstanding on the committed Bridge Facility. On September 25, 2017, we announced the sale of
our Suffield assets for gross cash proceeds of $512 million, plus a DPPA. In addition, on October 19, 2017, we announced the sale of our Palliser assets for gross cash proceeds of $1.3 billion. Both transactions are expected to close
in the fourth quarter of 2017, subject to customary closing conditions. Net proceeds from the divestitures will be applied against the committed Bridge Facility.
Cenovuss ability to service its increased debt will depend upon, among other things, its future financial and operating performance, which will be
affected by prevailing economic conditions, interest rate fluctuations and financial, business, regulatory and other factors, some of which are beyond Cenovuss control. If Cenovuss operating results are not sufficient to service its
current or future indebtedness, Cenovus may be forced to take actions such as reducing dividends, reducing or delaying business activities, investments or capital expenditures, selling assets, restructuring or refinancing its debt, or seeking
additional equity capital.
Our credit ratings could be lowered or withdrawn entirely by a rating agency if, in its judgment, the circumstances
warrant. The increased indebtedness of Cenovus arising from the Acquisition could be a factor considered by the ratings agencies in downgrading Cenovuss credit rating. If a rating agency were to downgrade Cenovuss credit
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rating, Cenovuss borrowing costs could increase and its funding sources could decrease. In addition, a failure by Cenovus to maintain its current credit ratings could affect its business
relationships with suppliers and operating partners. A credit downgrade could also adversely affect the availability and cost of capital needed to fund the growth investments that are a central element to Cenovuss long-term business strategy.
Suffield and Palliser Divestitures
We have announced the divestiture of our Suffield and Palliser assets, which are expected to close in the fourth quarter. Both divestitures are subject to
required regulatory approvals and the satisfaction of certain closing conditions. There is no certainty, nor can we provide any assurance, that these conditions will be satisfied or, if satisfied, when they will be satisfied. If they are not
satisfied or waived, the divestitures will not be completed. In addition, a substantial delay in obtaining regulatory approvals or the imposition of unfavourable terms or conditions in the approvals could have a material adverse effect on our
ability to complete the divestitures and on our business, financial condition, results of operations or cash flows following the divestitures. If the divestitures are not completed as contemplated, we could suffer adverse consequences, including the
loss of investor confidence.
British Columbia Exposure
Pursuant to the Acquisition, we acquired approximately 0.9 million gross acres (0.7 million net acres) of land holdings in British Columbia,
which exposes us to the following additional risks.
Aboriginal Claims
Aboriginal groups have claimed aboriginal title and rights to portions of Western Canada, including British Columbia, and such claims, if successful,
could have a material negative impact on Cenovus. The Governments of Canada and British Columbia have a duty to consult with Aboriginal people in relation to actions and decisions which may impact those rights and claims and, in certain cases, have
a duty to accommodate their concerns. These duties have the potential to adversely affect Cenovuss ability to obtain and renew permits, leases, licenses and other approvals, or to meet the terms and conditions of those approvals. The scope of
the duty to consult by the federal Government of Canada and the Government of British Columbia is subject to ongoing litigation which may result in uncertainty with respect to the process to obtain permits, leases, licenses and other approvals.
Opposition by Aboriginal groups may also negatively impact Cenovus in terms of public perception, diversion of Managements time and resources, legal and other advisory expenses, potential blockades or other interference by third parties in
Cenovuss operations, or court-ordered relief impacting Cenovuss operations. Challenges by Aboriginal groups could adversely impact Cenovuss progress and ability to explore and develop its properties.
Climate Change Regulation
On August 19, 2016, the Government of British Columbia unveiled its Climate Leadership Plan with a goal to reduce net annual GHG emissions by up to
25 million tonnes below current forecasts by 2050, and reaffirmed that it will achieve its 2050 target of an 80 percent reduction in emissions from 2007 levels. In addition to various measures across the economy that are designed to
incentivize the growth of the renewable energy sector, the use of low GHG emitting technologies, and the improvement of energy efficiency, among other goals, the Government of British Columbia has committed to implementing a formal policy to
regulate carbon capture and storage projects.
Further, the Climate Leadership Plan sets out a strategy to reduce methane emissions in the upstream
natural gas sector, beginning with a Legacy phase that targets a 45 percent reduction in fugitive and vented emissions by 2025 for facilities built before January 1, 2015, followed by a Transition phase for facilities built between 2015
and 2018 that will involve a new offset protocol and a Clean Infrastructure Royalty Credit Program, and finally a Future phase that will include the development and implementation of new methane emissions reduction standards.
Environmental Regulation
In British Columbia, the Oil and Gas Activities Act (the OGAA) impacts conventional crude oil and natural gas producers, shale gas producers
and other operators of crude oil and natural gas facilities in the province. Under the OGAA, the British Columbia Oil and Gas Commission (the Commission) has broad powers, particularly with respect to compliance and enforcement and the
setting of technical safety and operational standards for oil and natural gas activities. The Environmental Protection and Management Regulation establishes the governments environmental objectives for Crown lands for water, riparian habitats,
wildlife and wildlife habitat, old-growth forests and cultural heritage resources. The OGAA requires the Commission to consider these environmental objectives in deciding whether or not to authorize an oil and
gas activity. In addition, although not exclusively an environmental statute, the Petroleum and Natural Gas Act, in conjunction with the OGAA, requires companies to obtain various approvals before undertaking exploration or production work, such as
geophysical licences, geophysical exploration project approvals, permits for the exclusive right to do geological work and geophysical exploration work, and well, test hole and water-source well authorizations. Such approvals are given subject to
environmental considerations and licences and project approvals can be suspended or cancelled for failure to comply with this legislation or its regulations.
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Royalty Regime
Producers of crude oil and natural gas from Crown lands in British Columbia are required to pay annual rental payments, and make monthly royalty payments
in respect of crude oil and natural gas produced. The amount payable as a royalty in respect of crude oil depends on the type and vintage of the crude oil, the quantity of crude oil produced in a month and the value of that crude oil. Generally,
crude oil is classified as either light or heavy and the vintage of crude oil is classified as either: old oil that is produced from a pool with a completed well that first recovered crude oil before October 31, 1975; new
oil that is produced from a pool with a completed well that first recovered oil between October 31, 1975 and June 1, 1998; or third-tier oil that is produced from a pool with a completed well that first recovered crude
oil after June 1, 1998 or through an enhanced oil recovery scheme. The royalty calculation takes into account the production of crude oil on a well-by-well basis,
the specified royalty rate for a given vintage of crude oil, the average unit-selling price of the crude oil and any applicable royalty exemptions. Royalty rates are reduced on low-productivity wells,
reflecting the higher unit costs of extraction, and are the lowest for third-tier oil, reflecting the higher unit costs of both exploration and extraction.
The royalty payable in respect of natural gas produced on Crown lands is determined by a sliding scale formula based on a reference price, which is the
greater of the average net price obtained by the producer and a prescribed minimum price. For non-conservation gas (not produced in association with crude oil), the royalty rate depends on the date of
acquisition of the crude oil and natural gas tenure rights and the spud date of the well, and may also be impacted by the select price, a parameter used in the royalty rate formula to account for inflation. Royalty rates are fixed for certain
classes of non-conservation gas when the reference price is below the select price. Conservation gas is subject to a lower royalty rate than non-conservation gas.
Royalties on NGLs are levied at a flat rate of 20 percent of sales volume.
Producers of crude oil and natural gas from freehold lands in British
Columbia are required to pay monthly freehold production taxes. For crude oil, the applicable freehold production tax is based on the volume of monthly production, and is either a flat rate, or, beyond a certain production level, is determined using
a sliding scale formula based on the production level. For natural gas, the applicable freehold production tax is a flat rate, or, at certain production levels, is determined using a sliding scale formula based on the reference price similar to that
applied to natural gas production on Crown land, and depends on whether the natural gas is conservation gas or non-conservation gas. The production tax rate for freehold NGLs is a flat rate of
12.25 percent. Additionally, owners of mineral rights in British Columbia must pay an annual mineral land tax that is equivalent to $4.94 per hectare of producing lands. Non-producing lands are taxed on a
sliding scale between $1.25 $4.94 per hectare, depending on the total number of hectares owned by the entity.
The Government of British
Columbia maintains a number of targeted royalty programs for key resource areas intended to increase the competitiveness of British Columbias low productivity natural gas wells. These include both royalty credit and royalty reduction programs.
The Government of British Columbia also maintains an Infrastructure Royalty Credit Program that provides royalty credits for up to 50 percent of
the cost of certain approved road construction or pipeline infrastructure projects intended to facilitate increased crude oil and natural gas exploration and production in under-developed areas and to extend the drilling season.
Any future changes by the Government of British Columbia to the royalty programs or regimes could have a significant impact on Cenovuss financial
condition, results of operations and future capital expenditures.
CRITICAL ACCOUNTING JUDGMENTS, ESTIMATION UNCERTAINTIES 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 annual December 31, 2016 Consolidated Financial Statements and the interim Consolidated Financial Statements for the period ended September 30, 2017.
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 annual and interim Consolidated Financial Statements. There have been no changes to our critical judgments used in applying accounting policies during the nine months ended September 30, 2017. Further information can be
found in the notes to the Consolidated Financial Statements and annual MD&A for the year ended December 31, 2016.
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|
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Cenovus Energy Inc.
Third Quarter 2017 Report |
|
Page 50
Managements Discussion and Analysis |
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. Further to those areas discussed in the annual
Consolidated Financial Statements for the year ended December 31, 2016 and the annual MD&A, the estimation of fair values of the assets acquired and liabilities assumed in a business combination, including the contingent payment and
goodwill, is a key area involving significant estimates or judgments.
Recent Accounting Pronouncements
There were no new or amended accounting standards or interpretations adopted during the nine months ended September 30, 2017.
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 after
January 1, 2017 and have not been applied in preparing the interim Consolidated Financial Statements. The following provides an update to the disclosure in the annual Consolidated Financial Statements for the year ended December 31, 2016.
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. The standard may be applied retrospectively or using the retrospective
with cumulative effect approach. We are currently evaluating the impact of adopting IFRS 15 on the Consolidated Financial Statements and plan to adopt the standard for the year ended December 31, 2018.
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 has been adopted. The standard may be applied retrospectively or using a modified retrospective approach. The modified retrospective approach does not require restatement of prior period
financial information as it recognizes the cumulative effect as an adjustment to opening retained earnings and applies the standard prospectively.
We
plan to apply IFRS 16 on January 1, 2019. A transition team is assessing the impacts of adopting IFRS 16 and will oversee changes to accounting systems, processes and internal controls. The estimated time and effort necessary to develop and
implement required changes (including the impact to information technology systems) extends into 2018. Although the transition approach on adoption has not yet been determined, it is anticipated that the adoption of IFRS 16 will have a material
impact on the Consolidated Balance Sheets.
CONTROL ENVIRONMENT
Except for changes relating to the continuing
integration of the Deep Basin Assets, as discussed below, there have been no changes to internal control over financial reporting (ICFR) or disclosure controls and procedures (DC&P) during the three months ended
September 30, 2017 that have materially affected, or are reasonably likely to materially affect, ICFR or DC&P.
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Cenovus Energy Inc.
Third Quarter 2017 Report |
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Page 51
Managements Discussion and Analysis |
As permitted by and in accordance with, National Instrument 52-109,
Certification of Disclosure in Issuers Annual and Interim Filings, Management has limited the scope and design of ICFR and DC&P to exclude the controls, policies and procedures of the Deep Basin Assets that were acquired
on May 17, 2017 (see the Financing the Acquisition section of this MD&A for more details). Such scope limitation is primarily due to the time required for Management to assess the ICFR and DC&P relating to the Deep Basin Assets in a
manner consistent with our other operations. Summary financial information related to the Deep Basin Assets included in the interim Consolidated Financial Statements is as follows:
|
|
|
($ millions) |
|
Three Months Ended September 30, 2017 |
Revenues |
|
187 |
Operating Margin (1) |
|
64 |
Net Earnings (Loss) |
|
(27) |
As
at |
|
September 30, 2017 |
Current Assets |
|
130 |
Non-Current Assets
(1) |
|
6,570 |
Current Liabilities |
|
115 |
Non-Current Liabilities (1) |
|
621 |
(1) |
Summary financial information included within net earnings (loss), non-current
assets, and non-current liabilities includes both information obtained from predecessor accounting systems prior to full conversion to Cenovus systems, as well as financial information that is included in our
accounting systems, such as, property, plant and equipment, exploration and evaluation assets, decommissioning liabilities, and long-term incentive costs. |
In addition, we acquired approximately $500 million of Deep Basin commitments primarily consisting of transportation commitments on various
pipelines.
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.
OUTLOOK
We expect 2017 to be a transformational year
for Cenovus. The close of the Acquisition in the second quarter of 2017 increased our interest in FCCL to 100 percent and provided us with a second core operating area in the Deep Basin. As part of our ongoing efforts to optimize our asset
portfolio and focus on deleveraging our balance sheet, we announced our intention to sell our legacy Conventional crude oil and natural gas assets in the first half of 2017. In the third quarter, we successfully completed the sale of our Pelican
Lake assets and the adjacent Grand Rapids project, and announced the sale of our Suffield assets. Furthermore, on October 19, 2017, we announced the divestiture of our Palliser assets. Both transactions are expected to close in the fourth
quarter of 2017. The divestiture process for our remaining legacy Conventional assets, notably our CO2 enhanced oil recovery project at Weybum, in southern Saskatchewan, is proceeding well.
We believe we are well-positioned for continued market and commodity price volatility. We will continue to look for ways to increase our margins
through strong operating performance and cost leadership, while delivering safe and reliable operations. Proactively managing our market access commitments and opportunities should assist with our goal of reaching a broader customer base to secure a
higher sales price for our liquids production.
We have reduced the amount of capital needed to sustain our base business and expand our projects,
which we expect will allow us to reactivate growth in a disciplined manner. We believe these efforts will help to ensure our financial resilience.
The following outlook commentary is focused on the next twelve to fifteen 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, the impact of potential supply disruptions, and the pace of growth in global demand as influenced by macro-economic events. Overall, we expect crude oil price volatility to continue and a modest price improvement in the next fifteen
months. OPECs ability to adhere to its current production cuts and the possibility of future production cuts, combined with annual increases in demand growth should support prices, constrained by the need to draw down surplus crude oil
inventories and U.S. production growth; |
· |
|
We anticipate the Brent-WTI differential will narrow after the impacts of severe
weather related incidents dissipate and as a result of the U.S. exporting crude oil to overseas markets. Overall, the differential will likely be set by transportation costs; and |
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Cenovus Energy Inc.
Third Quarter 2017 Report |
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Page 52
Managements Discussion and Analysis |
· |
|
We expect that the WTI-WCS differential will widen due to Canadian supply
increasing due to the resolution of production outages, oil sands supply growth and potential transportation constraints, partially offset by the possibility of OPEC extending production cuts. |
|
|
|
Crude Oil Benchmarks
|
|
Natural Gas Benchmarks
|
Natural gas prices are anticipated to improve in the
fourth quarter of 2017 and first quarter of 2018 with a normal winter heating season and increased U.S. natural gas exports, partially offset by expected North American natural gas supply growth. In addition, recent pipeline and compressor station
maintenance within Alberta will increase exports out of western Canada, helping to improve AECO prices.
U.S. refining crack spreads are expected to
weaken in the fourth quarter of 2017 as refinery capacity returns after severe weather events and due to seasonal demand weakness. Seasonal demand changes will result in fluctuations of refining cracks spreads throughout the remainder of 2018. The
impact of weaker refining crack spreads on refinery margins will be partially offset by the widening of the WTI-WCS differential, which increases the refinery feedstock cost advantage.
We expect the Canadian dollar to continue to be tied to a modest improvement in crude oil prices and the pace at which the U.S. Federal Reserve Board and
the Bank of Canada raise benchmark lending rates. The Bank of Canada has raised its benchmark lending rate twice this year marking a notable shift for Canada towards a tighter monetary policy.
|
|
|
Refining 3-2-1 Crack Spread Benchmark
|
|
Foreign Exchange
|
Our exposure to the light/heavy price differentials
is composed of both a global light/heavy component as well as Canadian transportation constraints. While we expect to see volatility in crude oil prices, we have the ability to partially 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; |
|
|
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. |
Additional natural gas and NGLs production associated with the
Acquisition will provide improved upstream integration for the fuel, solvent and blending requirements at our oil sands operations.
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Cenovus Energy Inc.
Third Quarter 2017 Report |
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Page 53
Managements Discussion and Analysis |
Key Priorities for the Remainder of 2017
Maintain Financial Resilience and Executional Excellence
We remain focused on maintaining our financial resilience and flexibility while continuing to deliver safe operations, which remains a top priority.
Reducing our debt position is our number one priority. Our plans to divest our legacy Conventional assets are progressing and are on track. We are targeting between $4.0 billion and $5.0 billion, gross, in announced asset sale agreements
by the end of 2017, the proceeds of which will be used to retire the committed Bridge Facility and deleverage our balance sheet.
At
September 30, 2017, through a combination of cash and our committed credit facility, we have approximately $5.1 billion of liquidity. We believe our liquidity position and the downside protection from our commodity hedging program should
provide us the financial flexibility and resilience to maximize the value we realize on our asset sales and execute on our near-term deleveraging plan.
Disciplined and Value-Added Growth
In 2017, we anticipate capital investment to be between approximately $1.55 billion and $1.65 billion, a decline of six percent from our
guidance dated July 26, 2017, as a result of ongoing cost savings, efficiency improvements, divestiture activities, and our continued focus on capital discipline.
We intend to focus on optimizing our capital investment and development plans in the oil sands and Deep Basin for a variety of commodity price
environments. We will remain disciplined with a moderate pace of growth in the oil sands that continues to focus on controlling costs and capital efficiencies. We also anticipate a disciplined development approach to the Deep Basin Assets in 2017
and anticipate ramping up our activity levels through 2020. With integration remaining an important part of our overall strategy, capital investment is also allocated for scheduled maintenance and reliability work at the Refineries.
Cost and Margin Leadership
We remain committed to cost and margin leadership. We plan to continue to focus on reducing costs by leveraging our increased size and scale as well as
through the advancement of technologies and enhancing our base business. We believe there is an opportunity for operating cost reductions in the Deep Basin as we fully integrate these assets. Our ability to drive structural and sustainable cost and
margin improvements will further support our business plan and financial resilience.
Market Access
Market access constraints for Canadian crude oil continue to be a challenge. Our strategy is to maintain firm transportation commitments through a
combination of pipelines, rail and marine access to support our growth plans, but leave capacity for optimization. We expect to supplement firm capacity with active blending, storage, sourcing and destination optimization to ensure we are maximizing
the margin on every barrel we produce.
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|
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Cenovus Energy Inc.
Third Quarter 2017 Report |
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Page 54
Managements Discussion and Analysis |
CONSOLIDATED STATEMENTS OF EARNINGS (LOSS) (unaudited)
For the periods ended September 30,
($ millions, except per share amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
Notes |
|
|
2017 |
|
|
|
|
|
2016 |
|
|
|
|
|
2017 |
|
|
|
|
|
2016 |
|
|
|
|
|
|
|
|
|
|
|
|
(Restated) (1) |
|
|
|
|
|
|
|
|
|
|
|
(Restated) (1) |
|
|
|
|
|
|
|
|
|
|
Revenues |
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross Sales |
|
|
|
|
|
|
4,453 |
|
|
|
|
|
|
|
2,949 |
|
|
|
|
|
|
|
12,102 |
|
|
|
|
|
|
|
7,689 |
|
Less: Royalties |
|
|
|
|
|
|
67 |
|
|
|
|
|
|
|
4 |
|
|
|
|
|
|
|
138 |
|
|
|
|
|
|
|
7 |
|
|
|
|
|
|
|
|
4,386 |
|
|
|
|
|
|
|
2,945 |
|
|
|
|
|
|
|
11,964 |
|
|
|
|
|
|
|
7,682 |
|
Expenses |
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased Product |
|
|
|
|
|
|
1,667 |
|
|
|
|
|
|
|
1,917 |
|
|
|
|
|
|
|
5,981 |
|
|
|
|
|
|
|
4,903 |
|
Transportation and Blending |
|
|
|
|
|
|
1,083 |
|
|
|
|
|
|
|
428 |
|
|
|
|
|
|
|
2,534 |
|
|
|
|
|
|
|
1,224 |
|
Operating |
|
|
|
|
|
|
523 |
|
|
|
|
|
|
|
299 |
|
|
|
|
|
|
|
1,343 |
|
|
|
|
|
|
|
913 |
|
(Gain) Loss on Risk Management |
|
|
23 |
|
|
|
496 |
|
|
|
|
|
|
|
(27 |
) |
|
|
|
|
|
|
9 |
|
|
|
|
|
|
|
298 |
|
Depreciation, Depletion and Amortization |
|
|
7,13 |
|
|
|
552 |
|
|
|
|
|
|
|
247 |
|
|
|
|
|
|
|
1,181 |
|
|
|
|
|
|
|
692 |
|
Exploration Expense |
|
|
7,12 |
|
|
|
1 |
|
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
2 |
|
General and Administrative |
|
|
|
|
|
|
116 |
|
|
|
|
|
|
|
71 |
|
|
|
|
|
|
|
217 |
|
|
|
|
|
|
|
225 |
|
Finance Costs |
|
|
5 |
|
|
|
191 |
|
|
|
|
|
|
|
97 |
|
|
|
|
|
|
|
458 |
|
|
|
|
|
|
|
292 |
|
Interest Income |
|
|
|
|
|
|
(32 |
) |
|
|
|
|
|
|
(27 |
) |
|
|
|
|
|
|
(59 |
) |
|
|
|
|
|
|
(45 |
) |
Foreign Exchange (Gain) Loss, Net |
|
|
6 |
|
|
|
(350 |
) |
|
|
|
|
|
|
45 |
|
|
|
|
|
|
|
(836 |
) |
|
|
|
|
|
|
(338 |
) |
Revaluation (Gain) |
|
|
4 |
|
|
|
- |
|
|
|
|
|
|
|
- |
|
|
|
|
|
|
|
(2,524 |
) |
|
|
|
|
|
|
- |
|
Transaction Costs |
|
|
4 |
|
|
|
1 |
|
|
|
|
|
|
|
- |
|
|
|
|
|
|
|
56 |
|
|
|
|
|
|
|
- |
|
Re-measurement of Contingent Payment |
|
|
4,15 |
|
|
|
(43 |
) |
|
|
|
|
|
|
- |
|
|
|
|
|
|
|
(109 |
) |
|
|
|
|
|
|
- |
|
Research Costs |
|
|
|
|
|
|
6 |
|
|
|
|
|
|
|
5 |
|
|
|
|
|
|
|
15 |
|
|
|
|
|
|
|
30 |
|
(Gain) Loss on Divestiture of Assets |
|
|
|
|
|
|
(1 |
) |
|
|
|
|
|
|
5 |
|
|
|
|
|
|
|
- |
|
|
|
|
|
|
|
6 |
|
Other (Income) Loss, Net |
|
|
|
|
|
|
(2 |
) |
|
|
|
|
|
|
5 |
|
|
|
|
|
|
|
(4 |
) |
|
|
|
|
|
|
7 |
|
Earnings (Loss) From Continuing Operations Before Income Tax |
|
|
|
|
|
|
178 |
|
|
|
|
|
|
|
(121 |
) |
|
|
|
|
|
|
3,701 |
|
|
|
|
|
|
|
(527 |
) |
Income Tax Expense (Recovery) |
|
|
9 |
|
|
|
(110 |
) |
|
|
|
|
|
|
(66 |
) |
|
|
|
|
|
|
621 |
|
|
|
|
|
|
|
(277 |
) |
Net Earnings (Loss) From Continuing Operations |
|
|
|
|
|
|
288 |
|
|
|
|
|
|
|
(55 |
) |
|
|
|
|
|
|
3,080 |
|
|
|
|
|
|
|
(250 |
) |
Net Earnings (Loss) From Discontinued Operations |
|
|
8 |
|
|
|
(357 |
) |
|
|
|
|
|
|
(196 |
) |
|
|
|
|
|
|
(298 |
) |
|
|
|
|
|
|
(386 |
) |
Net Earnings (Loss) |
|
|
|
|
|
|
(69 |
) |
|
|
|
|
|
|
(251 |
) |
|
|
|
|
|
|
2,782 |
|
|
|
|
|
|
|
(636 |
) |
|
|
|
|
|
|
|
|
|
Basic and Diluted Earnings (Loss) Per Share ($) |
|
|
10 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Continuing Operations |
|
|
|
|
|
|
0.23 |
|
|
|
|
|
|
|
(0.07 |
) |
|
|
|
|
|
|
2.91 |
|
|
|
|
|
|
|
(0.30 |
) |
Discontinued Operations |
|
|
|
|
|
|
(0.29 |
) |
|
|
|
|
|
|
(0.23 |
) |
|
|
|
|
|
|
(0.29 |
) |
|
|
|
|
|
|
(0.46 |
) |
Net Earnings (Loss) Per Share |
|
|
|
|
|
|
(0.06 |
) |
|
|
|
|
|
|
(0.30 |
) |
|
|
|
|
|
|
2.62 |
|
|
|
|
|
|
|
(0.76 |
) |
(1) |
The comparative periods have been restated to reflect discontinued operations as discussed in Note 8. |
See
accompanying Notes to Consolidated Financial Statements (unaudited).
|
|
|
Cenovus Energy Inc.
Third Quarter 2017 Report |
|
Page 55
Consolidated Financial Statements |
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (unaudited)
For the periods ended September 30,
($ millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
Notes |
|
|
2017 |
|
|
|
|
|
2016 |
|
|
|
|
|
2017 |
|
|
|
|
|
2016 |
|
|
|
|
|
|
|
|
|
|
Net Earnings (Loss) |
|
|
|
|
|
|
(69 |
) |
|
|
|
|
|
|
(251 |
) |
|
|
|
|
|
|
2,782 |
|
|
|
|
|
|
|
(636 |
) |
Other Comprehensive Income (Loss), Net of Tax |
|
|
20 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Items That Will Not be Reclassified to Profit or Loss: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Actuarial Gain (Loss) Relating to Pension and Other Post-Retirement Benefits |
|
|
|
|
|
|
10 |
|
|
|
|
|
|
|
3 |
|
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
(9 |
) |
Items That May be Reclassified to Profit or Loss: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Available for Sale Financial Assets Change in Fair Value |
|
|
|
|
|
|
(1 |
) |
|
|
|
|
|
|
2 |
|
|
|
|
|
|
|
(1 |
) |
|
|
|
|
|
|
(2 |
) |
Available for Sale Financial Assets Reclassified to Profit or Loss |
|
|
|
|
|
|
- |
|
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
- |
|
|
|
|
|
|
|
1 |
|
Foreign Currency Translation Adjustment |
|
|
|
|
|
|
(148 |
) |
|
|
|
|
|
|
35 |
|
|
|
|
|
|
|
(290 |
) |
|
|
|
|
|
|
(205 |
) |
Total Other Comprehensive Income (Loss), Net of Tax |
|
|
|
|
|
|
(139 |
) |
|
|
|
|
|
|
41 |
|
|
|
|
|
|
|
(290 |
) |
|
|
|
|
|
|
(215 |
) |
Comprehensive Income (Loss) |
|
|
|
|
|
|
(208 |
) |
|
|
|
|
|
|
(210 |
) |
|
|
|
|
|
|
2,492 |
|
|
|
|
|
|
|
(851 |
) |
See accompanying Notes to Consolidated Financial Statements (unaudited).
|
|
|
Cenovus Energy Inc.
Third Quarter 2017 Report |
|
Page 56
Consolidated Financial Statements |
CONSOLIDATED BALANCE SHEETS (unaudited)
As at
($ millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Notes |
|
|
|
|
September 30, 2017 |
|
|
|
|
December 31, 2016 |
|
|
|
|
|
|
|
Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and Cash Equivalents |
|
|
|
|
|
|
|
|
632 |
|
|
|
|
|
3,720 |
|
Accounts Receivable and Accrued Revenues |
|
|
|
|
|
|
|
|
1,609 |
|
|
|
|
|
1,838 |
|
Income Tax Receivable |
|
|
|
|
|
|
|
|
6 |
|
|
|
|
|
6 |
|
Inventories |
|
|
11 |
|
|
|
|
|
1,122 |
|
|
|
|
|
1,237 |
|
Risk Management |
|
|
23,24 |
|
|
|
|
|
35 |
|
|
|
|
|
21 |
|
Assets Held for Sale |
|
|
8 |
|
|
|
|
|
1,805 |
|
|
|
|
|
- |
|
Total Current Assets |
|
|
|
|
|
|
|
|
5,209 |
|
|
|
|
|
6,822 |
|
Exploration and Evaluation Assets |
|
|
1,12 |
|
|
|
|
|
5,517 |
|
|
|
|
|
1,585 |
|
Property, Plant and Equipment, Net |
|
|
1,13 |
|
|
|
|
|
29,135 |
|
|
|
|
|
16,426 |
|
Income Tax Receivable |
|
|
|
|
|
|
|
|
309 |
|
|
|
|
|
124 |
|
Risk Management |
|
|
23,24 |
|
|
|
|
|
2 |
|
|
|
|
|
3 |
|
Other Assets |
|
|
|
|
|
|
|
|
61 |
|
|
|
|
|
56 |
|
Goodwill |
|
|
14 |
|
|
|
|
|
2,339 |
|
|
|
|
|
242 |
|
Total Assets |
|
|
|
|
|
|
|
|
42,572 |
|
|
|
|
|
25,258 |
|
Liabilities and Shareholders
Equity |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts Payable and Accrued Liabilities |
|
|
|
|
|
|
|
|
2,009 |
|
|
|
|
|
2,266 |
|
Income Tax Payable |
|
|
|
|
|
|
|
|
58 |
|
|
|
|
|
112 |
|
Risk Management |
|
|
23,24 |
|
|
|
|
|
321 |
|
|
|
|
|
293 |
|
Liabilities Related to Assets Held for Sale |
|
|
8 |
|
|
|
|
|
1,318 |
|
|
|
|
|
- |
|
Total Current Liabilities |
|
|
|
|
|
|
|
|
3,706 |
|
|
|
|
|
2,671 |
|
Long-Term Debt |
|
|
16 |
|
|
|
|
|
12,094 |
|
|
|
|
|
6,332 |
|
Contingent Payment |
|
|
15 |
|
|
|
|
|
252 |
|
|
|
|
|
- |
|
Risk Management |
|
|
23,24 |
|
|
|
|
|
29 |
|
|
|
|
|
22 |
|
Decommissioning Liabilities |
|
|
17 |
|
|
|
|
|
1,109 |
|
|
|
|
|
1,847 |
|
Other Liabilities |
|
|
18 |
|
|
|
|
|
184 |
|
|
|
|
|
211 |
|
Deferred Income Taxes |
|
|
|
|
|
|
|
|
5,765 |
|
|
|
|
|
2,585 |
|
Total Liabilities |
|
|
|
|
|
|
|
|
23,139 |
|
|
|
|
|
13,668 |
|
Shareholders Equity |
|
|
|
|
|
|
|
|
19,433 |
|
|
|
|
|
11,590 |
|
Total Liabilities and Shareholders Equity |
|
|
|
|
|
|
|
|
42,572 |
|
|
|
|
|
25,258 |
|
See accompanying Notes to Consolidated Financial Statements (unaudited).
|
|
|
Cenovus Energy Inc.
Third Quarter 2017 Report |
|
Page 57
Consolidated Financial Statements |
CONSOLIDATED STATEMENTS OF SHAREHOLDERS EQUITY (unaudited)
($ millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Share
Capital |
|
|
|
|
Paid in
Surplus |
|
|
|
|
Retained
Earnings |
|
|
|
|
AOCI (1) |
|
|
|
|
Total |
|
|
|
|
(Note 19 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Note 20 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As at December 31, 2015 |
|
|
5,534 |
|
|
|
|
|
4,330 |
|
|
|
|
|
1,507 |
|
|
|
|
|
1,020 |
|
|
|
|
|
12,391 |
|
Net Earnings (Loss) |
|
|
- |
|
|
|
|
|
- |
|
|
|
|
|
(636 |
) |
|
|
|
|
- |
|
|
|
|
|
(636 |
) |
Other Comprehensive Income (Loss) |
|
|
- |
|
|
|
|
|
- |
|
|
|
|
|
- |
|
|
|
|
|
(215 |
) |
|
|
|
|
(215 |
) |
Total Comprehensive Income (Loss) |
|
|
- |
|
|
|
|
|
- |
|
|
|
|
|
(636 |
) |
|
|
|
|
(215 |
) |
|
|
|
|
(851 |
) |
Stock-Based Compensation Expense |
|
|
- |
|
|
|
|
|
15 |
|
|
|
|
|
- |
|
|
|
|
|
- |
|
|
|
|
|
15 |
|
Dividends on Common Shares |
|
|
- |
|
|
|
|
|
- |
|
|
|
|
|
(124 |
) |
|
|
|
|
- |
|
|
|
|
|
(124 |
) |
As at September 30, 2016 |
|
|
5,534 |
|
|
|
|
|
4,345 |
|
|
|
|
|
747 |
|
|
|
|
|
805 |
|
|
|
|
|
11,431 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As at December 31, 2016 |
|
|
5,534 |
|
|
|
|
|
4,350 |
|
|
|
|
|
796 |
|
|
|
|
|
910 |
|
|
|
|
|
11,590 |
|
Net Earnings (Loss) |
|
|
- |
|
|
|
|
|
- |
|
|
|
|
|
2,782 |
|
|
|
|
|
- |
|
|
|
|
|
2,782 |
|
Other Comprehensive Income (Loss) |
|
|
- |
|
|
|
|
|
- |
|
|
|
|
|
- |
|
|
|
|
|
(290 |
) |
|
|
|
|
(290 |
) |
Total Comprehensive Income (Loss) |
|
|
- |
|
|
|
|
|
- |
|
|
|
|
|
2,782 |
|
|
|
|
|
(290 |
) |
|
|
|
|
2,492 |
|
Common Shares Issued |
|
|
5,506 |
|
|
|
|
|
- |
|
|
|
|
|
- |
|
|
|
|
|
- |
|
|
|
|
|
5,506 |
|
Stock-Based Compensation Expense |
|
|
- |
|
|
|
|
|
9 |
|
|
|
|
|
- |
|
|
|
|
|
- |
|
|
|
|
|
9 |
|
Dividends on Common Shares |
|
|
- |
|
|
|
|
|
- |
|
|
|
|
|
(164 |
) |
|
|
|
|
- |
|
|
|
|
|
(164 |
) |
As at September 30, 2017 |
|
|
11,040 |
|
|
|
|
|
4,359 |
|
|
|
|
|
3,414 |
|
|
|
|
|
620 |
|
|
|
|
|
19,433 |
|
(1) |
Accumulated Other Comprehensive Income (Loss). |
See accompanying Notes to Consolidated Financial Statements
(unaudited).
|
|
|
Cenovus Energy Inc.
Third Quarter 2017 Report |
|
Page 58
Consolidated Financial Statements |
CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)
For the periods ended September 30,
($ millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
|
Nine Months Ended |
|
|
|
Notes |
|
|
2017 |
|
|
|
|
2016 |
|
|
|
|
2017 |
|
|
|
|
2016 |
|
|
|
|
|
|
|
|
|
|
Operating Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Earnings (Loss) |
|
|
|
|
|
|
(69) |
|
|
|
|
|
(251) |
|
|
|
|
|
2,782 |
|
|
|
|
|
(636) |
|
Depreciation, Depletion and Amortization |
|
|
7,13 |
|
|
|
552 |
|
|
|
|
|
659 |
|
|
|
|
|
1,371 |
|
|
|
|
|
1,569 |
|
Exploration Expense |
|
|
|
|
|
|
1 |
|
|
|
|
|
1 |
|
|
|
|
|
3 |
|
|
|
|
|
2 |
|
Deferred Income Taxes |
|
|
9 |
|
|
|
(182) |
|
|
|
|
|
(111) |
|
|
|
|
|
757 |
|
|
|
|
|
(353) |
|
Unrealized (Gain) Loss on Risk Management |
|
|
23 |
|
|
|
486 |
|
|
|
|
|
7 |
|
|
|
|
|
75 |
|
|
|
|
|
440 |
|
Unrealized Foreign Exchange (Gain) Loss |
|
|
6 |
|
|
|
(440) |
|
|
|
|
|
50 |
|
|
|
|
|
(908) |
|
|
|
|
|
(341) |
|
Revaluation (Gain) |
|
|
4 |
|
|
|
- |
|
|
|
|
|
- |
|
|
|
|
|
(2,524) |
|
|
|
|
|
- |
|
Re-measurement of Contingent Payment |
|
|
15 |
|
|
|
(43) |
|
|
|
|
|
- |
|
|
|
|
|
(109) |
|
|
|
|
|
- |
|
Loss on Discontinuance |
|
|
8 |
|
|
|
603 |
|
|
|
|
|
- |
|
|
|
|
|
603 |
|
|
|
|
|
- |
|
(Gain) Loss on Divestiture of Assets |
|
|
|
|
|
|
(1) |
|
|
|
|
|
5 |
|
|
|
|
|
- |
|
|
|
|
|
6 |
|
Unwinding of Discount on Decommissioning Liabilities |
|
|
17 |
|
|
|
19 |
|
|
|
|
|
33 |
|
|
|
|
|
68 |
|
|
|
|
|
97 |
|
Onerous Contract Provisions, Net of Cash Paid |
|
|
|
|
|
|
(2) |
|
|
|
|
|
(4) |
|
|
|
|
|
(7) |
|
|
|
|
|
26 |
|
Other |
|
|
|
|
|
|
58 |
|
|
|
|
|
33 |
|
|
|
|
|
(14) |
|
|
|
|
|
78 |
|
Net Change in Other Assets and Liabilities |
|
|
|
|
|
|
(19) |
|
|
|
|
|
(13) |
|
|
|
|
|
(75) |
|
|
|
|
|
(59) |
|
Net Change in Non-Cash Working Capital |
|
|
|
|
|
|
(371) |
|
|
|
|
|
(99) |
|
|
|
|
|
137 |
|
|
|
|
|
(132) |
|
Cash From Operating Activities |
|
|
|
|
|
|
592 |
|
|
|
|
|
310 |
|
|
|
|
|
2,159 |
|
|
|
|
|
697 |
|
|
|
|
|
|
|
|
|
|
Investing Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisition, Net of Cash Acquired |
|
|
4 |
|
|
|
(63) |
|
|
|
|
|
- |
|
|
|
|
|
(14,562) |
|
|
|
|
|
- |
|
Capital Expenditures Exploration and Evaluation Assets |
|
|
12 |
|
|
|
(52) |
|
|
|
|
|
(3) |
|
|
|
|
|
(128) |
|
|
|
|
|
(56) |
|
Capital Expenditures Property, Plant and Equipment |
|
|
13 |
|
|
|
(391) |
|
|
|
|
|
(205) |
|
|
|
|
|
(955) |
|
|
|
|
|
(719) |
|
Proceeds From Divestiture of Assets |
|
|
|
|
|
|
939 |
|
|
|
|
|
8 |
|
|
|
|
|
939 |
|
|
|
|
|
8 |
|
Net Change in Investments and Other |
|
|
|
|
|
|
(1) |
|
|
|
|
|
- |
|
|
|
|
|
- |
|
|
|
|
|
- |
|
Net Change in Non-Cash Working Capital |
|
|
|
|
|
|
80 |
|
|
|
|
|
4 |
|
|
|
|
|
53 |
|
|
|
|
|
(68) |
|
Cash From (Used in) Investing Activities |
|
|
|
|
|
|
512 |
|
|
|
|
|
(196) |
|
|
|
|
|
(14,653) |
|
|
|
|
|
(835) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Provided (Used) Before Financing Activities |
|
|
|
|
|
|
1,104 |
|
|
|
|
|
114 |
|
|
|
|
|
(12,494) |
|
|
|
|
|
(138) |
|
|
|
|
|
|
|
|
|
|
Financing Activities |
|
|
25 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of Long-Term Debt |
|
|
16 |
|
|
|
- |
|
|
|
|
|
- |
|
|
|
|
|
3,842 |
|
|
|
|
|
- |
|
Net Issuance (Repayment) of Revolving Long-Term Debt |
|
|
16 |
|
|
|
3 |
|
|
|
|
|
- |
|
|
|
|
|
33 |
|
|
|
|
|
- |
|
Issuance of Debt Under Asset Sale Bridge Facility |
|
|
16 |
|
|
|
- |
|
|
|
|
|
- |
|
|
|
|
|
3,569 |
|
|
|
|
|
- |
|
(Repayment) of Debt Under Asset Sale Bridge Facility |
|
|
16 |
|
|
|
(950) |
|
|
|
|
|
- |
|
|
|
|
|
(950) |
|
|
|
|
|
- |
|
Common Shares Issued, Net of Issuance Costs |
|
|
4,19 |
|
|
|
- |
|
|
|
|
|
- |
|
|
|
|
|
2,899 |
|
|
|
|
|
- |
|
Dividends Paid on Common Shares |
|
|
10 |
|
|
|
(62) |
|
|
|
|
|
(41) |
|
|
|
|
|
(164) |
|
|
|
|
|
(124) |
|
Other |
|
|
|
|
|
|
- |
|
|
|
|
|
- |
|
|
|
|
|
(2) |
|
|
|
|
|
(1) |
|
Cash From (Used in) Financing Activities |
|
|
|
|
|
|
(1,009) |
|
|
|
|
|
(41) |
|
|
|
|
|
9,227 |
|
|
|
|
|
(125) |
|
|
|
|
|
|
|
|
|
|
Foreign Exchange Gain (Loss) on Cash and Cash Equivalents Held in Foreign Currency |
|
|
|
|
|
|
48 |
|
|
|
|
|
(3) |
|
|
|
|
|
179 |
|
|
|
|
|
8 |
|
Increase (Decrease) in Cash and Cash Equivalents |
|
|
|
|
|
|
143 |
|
|
|
|
|
70 |
|
|
|
|
|
(3,088) |
|
|
|
|
|
(255) |
|
Cash and Cash Equivalents, Beginning of Period |
|
|
|
|
|
|
489 |
|
|
|
|
|
3,780 |
|
|
|
|
|
3,720 |
|
|
|
|
|
4,105 |
|
Cash and Cash Equivalents, End of Period |
|
|
|
|
|
|
632 |
|
|
|
|
|
3,850 |
|
|
|
|
|
632 |
|
|
|
|
|
3,850 |
|
See accompanying Notes to Consolidated Financial Statements (unaudited).
|
|
|
Cenovus Energy Inc.
Third Quarter 2017 Report |
|
Page 59
Consolidated Financial Statements |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
All amounts in $ millions, unless otherwise indicated
For the period ended September 30, 2017
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 interim Consolidated Financial Statements is found in Note 2.
On May 17, 2017, Cenovus acquired from ConocoPhillips Company and
certain of its subsidiaries (collectively, ConocoPhillips) a 50 percent interest in FCCL Partnership (FCCL) and the majority of ConocoPhillips western Canadian conventional crude oil and natural gas assets (the
Deep Basin Assets). This acquisition increased Cenovuss interest in FCCL to 100 percent and expanded Cenovuss operating areas to include more than three million net acres of land, exploration and production assets and
related infrastructure and agreements in Alberta and British Columbia. The acquisition had an effective date of January 1, 2017 (see Note 4).
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 margin. 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 Telephone Lake. The Companys interest in certain of its operated oil sands properties, notably
Foster Creek, Christina Lake and Narrows Lake, increased from 50 percent to 100 percent on May 17, 2017. |
|
|
|
Deep Basin, which includes approximately three million net acres of land primarily in the Elmworth-Wapiti,
Kaybob-Edson, and Clearwater operating areas, rich in natural gas and NGLs. The assets reside in Alberta and British Columbia and include interests in numerous natural gas processing facilities. The Deep Basin Assets were acquired on May 17,
2017. |
|
|
|
Conventional, which has been classified as a discontinued operation as the Company commenced marketing for sale
its Conventional assets. This segment 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 reportable 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.
Third Quarter 2017 Report |
|
Page 60
Notes to Consolidated Financial Statements |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
All amounts in $ millions, unless otherwise indicated
For the period ended September 30, 2017
A) Results of Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil Sands |
|
|
|
Deep Basin |
|
|
|
Refining and Marketing |
For the three months ended September 30, |
|
2017 |
|
|
|
2016 |
|
|
|
2017 |
|
|
|
2016 |
|
|
|
2017 |
|
|
|
2016 |
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross Sales |
|
2,210 |
|
|
|
793 |
|
|
|
200 |
|
|
|
- |
|
|
|
2,161 |
|
|
|
2,245 |
Less: Royalties |
|
54 |
|
|
|
4 |
|
|
|
13 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
2,156 |
|
|
|
789 |
|
|
|
187 |
|
|
|
- |
|
|
|
2,161 |
|
|
|
2,245 |
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased Product |
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
1,782 |
|
|
|
2,004 |
Transportation and Blending |
|
1,066 |
|
|
|
429 |
|
|
|
22 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
Operating |
|
257 |
|
|
|
128 |
|
|
|
101 |
|
|
|
- |
|
|
|
168 |
|
|
|
172 |
(Gain) Loss on Risk Management |
|
9 |
|
|
|
(35) |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
1 |
Operating Margin |
|
824 |
|
|
|
267 |
|
|
|
64 |
|
|
|
- |
|
|
|
211 |
|
|
|
68 |
Depreciation, Depletion and Amortization |
|
393 |
|
|
|
181 |
|
|
|
91 |
|
|
|
- |
|
|
|
53 |
|
|
|
52 |
Exploration Expense |
|
1 |
|
|
|
1 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
Segment Income (Loss) |
|
430 |
|
|
|
85 |
|
|
|
(27) |
|
|
|
- |
|
|
|
158 |
|
|
|
16 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate and
Eliminations |
|
|
|
Consolidated |
For the three months ended September 30, |
|
|
|
|
|
|
|
|
|
2017 |
|
|
|
2016 |
|
|
|
2017 |
|
|
|
2016 |
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross Sales |
|
|
|
|
|
|
|
|
|
(118) |
|
|
|
(89) |
|
|
|
4,453 |
|
|
|
2,949 |
Less: Royalties |
|
|
|
|
|
|
|
|
|
- |
|
|
|
- |
|
|
|
67 |
|
|
|
4 |
|
|
|
|
|
|
|
|
|
|
(118) |
|
|
|
(89) |
|
|
|
4,386 |
|
|
|
2,945 |
|
|
|
|
|
|
|
|
|
|
|
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased Product |
|
|
|
|
|
|
|
|
|
(115) |
|
|
|
(87) |
|
|
|
1,667 |
|
|
|
1,917 |
Transportation and Blending |
|
|
|
|
|
|
|
|
|
(5) |
|
|
|
(1) |
|
|
|
1,083 |
|
|
|
428 |
Operating |
|
|
|
|
|
|
|
|
|
(3) |
|
|
|
(1) |
|
|
|
523 |
|
|
|
299 |
(Gain) Loss on Risk Management |
|
|
|
|
|
|
|
|
|
487 |
|
|
|
7 |
|
|
|
496 |
|
|
|
(27) |
Depreciation, Depletion and Amortization |
|
|
|
|
|
|
|
|
|
15 |
|
|
|
14 |
|
|
|
552 |
|
|
|
247 |
Exploration Expense |
|
|
|
|
|
|
|
|
|
- |
|
|
|
- |
|
|
|
1 |
|
|
|
1 |
Segment Income (Loss) |
|
|
|
|
|
|
|
|
|
(497) |
|
|
|
(21) |
|
|
|
64 |
|
|
|
80 |
General and Administrative |
|
|
|
|
|
|
|
|
|
116 |
|
|
|
71 |
|
|
|
116 |
|
|
|
71 |
Finance Costs |
|
|
|
|
|
|
|
|
|
191 |
|
|
|
97 |
|
|
|
191 |
|
|
|
97 |
Interest Income |
|
|
|
|
|
|
|
|
|
(32) |
|
|
|
(27) |
|
|
|
(32) |
|
|
|
(27) |
Foreign Exchange (Gain) Loss, Net |
|
|
|
|
|
|
|
|
|
(350) |
|
|
|
45 |
|
|
|
(350) |
|
|
|
45 |
Revaluation (Gain) |
|
|
|
|
|
|
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
Transaction Costs |
|
|
|
|
|
|
|
|
|
1 |
|
|
|
- |
|
|
|
1 |
|
|
|
- |
Re-measurement of Contingent Payment |
|
|
|
|
|
|
|
|
|
(43) |
|
|
|
- |
|
|
|
(43) |
|
|
|
- |
Research Costs |
|
|
|
|
|
|
|
|
|
6 |
|
|
|
5 |
|
|
|
6 |
|
|
|
5 |
(Gain) Loss on Divestiture of Assets |
|
|
|
|
|
|
|
|
|
(1) |
|
|
|
5 |
|
|
|
(1) |
|
|
|
5 |
Other (Income) Loss, Net |
|
|
|
|
|
|
|
|
|
(2) |
|
|
|
5 |
|
|
|
(2) |
|
|
|
5 |
|
|
|
|
|
|
|
|
|
|
(114) |
|
|
|
201 |
|
|
|
(114) |
|
|
|
201 |
Earnings (Loss) From Continuing Operations Before Income Tax |
|
|
|
|
|
|
|
|
|
|
|
178 |
|
|
|
(121) |
Income Tax Expense (Recovery) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(110) |
|
|
|
(66) |
Net Earnings (Loss) From Continuing Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
288 |
|
|
|
(55) |
|
|
|
Cenovus Energy Inc.
Third Quarter 2017 Report |
|
Page 61
Notes to Consolidated Financial Statements |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
All amounts in $ millions, unless otherwise indicated
For the period ended September 30, 2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil Sands |
|
|
|
Deep Basin |
|
|
|
Refining and Marketing |
For the nine months ended September 30, |
|
2017 |
|
|
|
2016 |
|
|
|
2017 |
|
|
|
2016 |
|
|
|
2017 |
|
|
|
2016 |
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross Sales |
|
4,938 |
|
|
|
1,972 |
|
|
|
324 |
|
|
|
- |
|
|
|
7,162 |
|
|
|
5,962 |
Less: Royalties |
|
117 |
|
|
|
7 |
|
|
|
21 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
4,821 |
|
|
|
1,965 |
|
|
|
303 |
|
|
|
- |
|
|
|
7,162 |
|
|
|
5,962 |
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased Product |
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
6,295 |
|
|
|
5,144 |
Transportation and Blending |
|
2,511 |
|
|
|
1,228 |
|
|
|
32 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
Operating |
|
618 |
|
|
|
359 |
|
|
|
152 |
|
|
|
- |
|
|
|
579 |
|
|
|
557 |
(Gain) Loss on Risk Management |
|
72 |
|
|
|
(165) |
|
|
|
- |
|
|
|
- |
|
|
|
4 |
|
|
|
23 |
Operating Margin |
|
1,620 |
|
|
|
543 |
|
|
|
119 |
|
|
|
- |
|
|
|
284 |
|
|
|
238 |
Depreciation, Depletion and Amortization |
|
836 |
|
|
|
485 |
|
|
|
136 |
|
|
|
- |
|
|
|
162 |
|
|
|
157 |
Exploration Expense |
|
1 |
|
|
|
2 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
Segment Income (Loss) |
|
783 |
|
|
|
56 |
|
|
|
(17) |
|
|
|
- |
|
|
|
122 |
|
|
|
81 |
|
|
|
|
|
|
|
|
|
|
|
|
Corporate and Eliminations |
|
|
|
Consolidated |
For the nine months ended September 30, |
|
|
|
|
|
|
|
|
|
2017 |
|
|
|
2016 |
|
|
|
2017 |
|
|
|
2016 |
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross Sales |
|
|
|
|
|
|
|
|
|
(322) |
|
|
|
(245) |
|
|
|
12,102 |
|
|
|
7,689 |
Less: Royalties |
|
|
|
|
|
|
|
|
|
- |
|
|
|
- |
|
|
|
138 |
|
|
|
7 |
|
|
|
|
|
|
|
|
|
|
(322) |
|
|
|
(245) |
|
|
|
11,964 |
|
|
|
7,682 |
|
|
|
|
|
|
|
|
|
|
|
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased Product |
|
|
|
|
|
|
|
|
|
(314) |
|
|
|
(241) |
|
|
|
5,981 |
|
|
|
4,903 |
Transportation and Blending |
|
|
|
|
|
|
|
|
|
(9) |
|
|
|
(4) |
|
|
|
2,534 |
|
|
|
1,224 |
Operating |
|
|
|
|
|
|
|
|
|
(6) |
|
|
|
(3) |
|
|
|
1,343 |
|
|
|
913 |
(Gain) Loss on Risk Management |
|
|
|
|
|
|
|
|
|
(67) |
|
|
|
440 |
|
|
|
9 |
|
|
|
298 |
Depreciation, Depletion and Amortization |
|
|
|
|
|
|
|
|
|
47 |
|
|
|
50 |
|
|
|
1,181 |
|
|
|
692 |
Exploration Expense |
|
|
|
|
|
|
|
|
|
- |
|
|
|
- |
|
|
|
1 |
|
|
|
2 |
Segment Income (Loss) |
|
|
|
|
|
|
|
|
|
27 |
|
|
|
(487) |
|
|
|
915 |
|
|
|
(350) |
General and Administrative |
|
|
|
|
|
|
|
|
|
217 |
|
|
|
225 |
|
|
|
217 |
|
|
|
225 |
Finance Costs |
|
|
|
|
|
|
|
|
|
458 |
|
|
|
292 |
|
|
|
458 |
|
|
|
292 |
Interest Income |
|
|
|
|
|
|
|
|
|
(59) |
|
|
|
(45) |
|
|
|
(59) |
|
|
|
(45) |
Foreign Exchange (Gain) Loss, Net |
|
|
|
|
|
|
|
|
|
(836) |
|
|
|
(338) |
|
|
|
(836) |
|
|
|
(338) |
Revaluation (Gain) |
|
|
|
|
|
|
|
|
|
(2,524) |
|
|
|
- |
|
|
|
(2,524) |
|
|
|
- |
Transaction Costs |
|
|
|
|
|
|
|
|
|
56 |
|
|
|
- |
|
|
|
56 |
|
|
|
- |
Re-measurement of Contingent Payment |
|
|
|
|
|
|
|
|
|
(109) |
|
|
|
- |
|
|
|
(109) |
|
|
|
- |
Research Costs |
|
|
|
|
|
|
|
|
|
15 |
|
|
|
30 |
|
|
|
15 |
|
|
|
30 |
(Gain) Loss on Divestiture of Assets |
|
|
|
|
|
|
|
|
|
- |
|
|
|
6 |
|
|
|
- |
|
|
|
6 |
Other (Income) Loss, Net |
|
|
|
|
|
|
|
|
|
(4) |
|
|
|
7 |
|
|
|
(4) |
|
|
|
7 |
|
|
|
|
|
|
|
|
|
|
(2,786) |
|
|
|
177 |
|
|
|
(2,786) |
|
|
|
177 |
Earnings (Loss) From Continuing Operations Before Income Tax |
|
|
|
|
|
|
|
|
|
|
|
3,701 |
|
|
|
(527) |
Income Tax Expense (Recovery) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
621 |
|
|
|
(277) |
Net Earnings (Loss) From Continuing Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,080 |
|
|
|
(250) |
|
|
|
Cenovus Energy Inc.
Third Quarter 2017 Report |
|
Page 62
Notes to Consolidated Financial Statements |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
All amounts in $ millions, unless otherwise indicated
For the period ended September 30, 2017
B) Revenues by Product
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
Nine Months Ended |
For the periods ended September 30, |
|
2017 |
|
|
|
2016 |
|
|
|
2017 |
|
|
|
2016 |
|
|
|
|
|
|
|
|
Upstream |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil |
|
2,178 |
|
|
|
784 |
|
|
|
4,845 |
|
|
|
1,953 |
Natural Gas (1) |
|
79 |
|
|
|
5 |
|
|
|
151 |
|
|
|
11 |
NGLs |
|
68 |
|
|
|
- |
|
|
|
100 |
|
|
|
- |
Other |
|
18 |
|
|
|
- |
|
|
|
28 |
|
|
|
1 |
Refining and Marketing |
|
2,161 |
|
|
|
2,245 |
|
|
|
7,162 |
|
|
|
5,962 |
Corporate and Eliminations |
|
(118) |
|
|
|
(89) |
|
|
|
(322) |
|
|
|
(245) |
Revenues From Continuing Operations |
|
4,386 |
|
|
|
2,945 |
|
|
|
11,964 |
|
|
|
7,682 |
(1) |
In the three and nine months ending September 30, 2017, approximately 18 percent and 15 percent, respectively, of the natural gas produced by Cenovuss Deep Basin Assets was sold to ConocoPhillips
resulting in gross sales of $14 million and $22 million, respectively. |
C) Geographical Information
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
|
Three Months Ended |
|
Nine Months Ended |
For the periods ended September 30, |
|
2017 |
|
|
|
2016 |
|
|
|
2017 |
|
|
|
2016 |
|
|
|
|
|
|
|
|
Canada |
|
2,577 |
|
|
|
1,328 |
|
|
|
6,753 |
|
|
|
3,330 |
United States |
|
1,809 |
|
|
|
1,617 |
|
|
|
5,211 |
|
|
|
4,352 |
Revenues From Continuing Operations |
|
4,386 |
|
|
|
2,945 |
|
|
|
11,964 |
|
|
|
7,682 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-Current Assets (1) |
|
|
|
|
|
|
|
|
|
|
September 30, |
|
|
|
December 31, |
As at |
|
|
|
|
|
|
|
|
|
2017 |
|
|
|
2016 |
|
|
|
|
|
|
|
|
Canada (2) |
|
|
|
|
|
|
|
|
|
33,206 |
|
|
|
14,130 |
United States |
|
|
|
|
|
|
|
|
|
3,846 |
|
|
|
4,179 |
Consolidated |
|
|
|
|
|
|
|
|
|
37,052 |
|
|
|
18,309 |
(1) |
Includes exploration and evaluation (E&E) assets, property, plant and equipment (PP&E), goodwill and other assets. |
(2) |
Non-current assets of the Conventional segment, which resides in Canada, have been reclassified as held for sale in 2017 in current assets. 2016 includes $3.1 billion of non-current assets related to the Conventional segment. |
D) Exploration and Evaluation
Assets, Property, Plant and Equipment, Goodwill and Total Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
E&E |
|
|
|
PP&E |
|
|
September 30, |
|
|
|
December 31, |
|
|
|
September 30, |
|
|
|
December 31, |
As at |
|
2017 |
|
|
|
2016 |
|
|
|
2017 |
|
|
|
2016 |
|
|
|
|
|
|
|
|
Oil Sands |
|
1,877 |
|
|
|
1,564 |
|
|
|
21,997 |
|
|
|
8,798 |
Deep Basin |
|
3,640 |
|
|
|
- |
|
|
|
2,930 |
|
|
|
- |
Conventional |
|
- |
|
|
|
21 |
|
|
|
- |
|
|
|
3,080 |
Refining and Marketing |
|
- |
|
|
|
- |
|
|
|
3,943 |
|
|
|
4,273 |
Corporate and Eliminations |
|
- |
|
|
|
- |
|
|
|
265 |
|
|
|
275 |
Consolidated |
|
5,517 |
|
|
|
1,585 |
|
|
|
29,135 |
|
|
|
16,426 |
|
|
|
|
|
|
Goodwill |
|
|
|
Total Assets |
|
|
September 30, |
|
|
|
December 31, |
|
|
|
September 30, |
|
|
|
December 31, |
As at |
|
2017 |
|
|
|
2016 |
|
|
|
2017 |
|
|
|
2016 |
|
|
|
|
|
|
|
|
Oil Sands |
|
2,339 |
|
|
|
242 |
|
|
|
27,452 |
|
|
|
11,112 |
Deep Basin |
|
- |
|
|
|
- |
|
|
|
6,700 |
|
|
|
- |
Conventional |
|
- |
|
|
|
- |
|
|
|
1,966 |
|
|
|
3,196 |
Refining and Marketing |
|
- |
|
|
|
- |
|
|
|
5,115 |
|
|
|
6,613 |
Corporate and Eliminations |
|
- |
|
|
|
- |
|
|
|
1,339 |
|
|
|
4,337 |
Consolidated |
|
2,339 |
|
|
|
242 |
|
|
|
42,572 |
|
|
|
25,258 |
|
|
|
Cenovus Energy Inc.
Third Quarter 2017 Report |
|
Page 63
Notes to Consolidated Financial Statements |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
All amounts in $ millions, unless otherwise indicated
For the period ended September 30, 2017
E) Capital Expenditures (1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
For the periods ended September 30, |
|
2017 |
|
|
|
|
2016 |
|
|
|
|
2017 |
|
|
|
|
2016 |
|
|
|
|
|
|
|
|
Capital |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil Sands |
|
273 |
|
|
|
|
|
110 |
|
|
|
|
|
660 |
|
|
|
|
|
476 |
Deep Basin |
|
64 |
|
|
|
|
|
- |
|
|
|
|
|
77 |
|
|
|
|
|
- |
Conventional |
|
42 |
|
|
|
|
|
41 |
|
|
|
|
|
180 |
|
|
|
|
|
114 |
Refining and Marketing |
|
38 |
|
|
|
|
|
51 |
|
|
|
|
|
124 |
|
|
|
|
|
156 |
Corporate |
|
21 |
|
|
|
|
|
6 |
|
|
|
|
|
37 |
|
|
|
|
|
21 |
Capital Investment |
|
438 |
|
|
|
|
|
208 |
|
|
|
|
|
1,078 |
|
|
|
|
|
767 |
|
|
|
|
|
|
|
|
Acquisition Capital |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil Sands (2) |
|
3 |
|
|
|
|
|
- |
|
|
|
|
|
11,607 |
|
|
|
|
|
11 |
Deep Basin |
|
67 |
|
|
|
|
|
- |
|
|
|
|
|
6,694 |
|
|
|
|
|
- |
Total Capital Expenditures |
|
508 |
|
|
|
|
|
208 |
|
|
|
|
|
19,379 |
|
|
|
|
|
778 |
(1) |
Includes expenditures on PP&E, E&E assets and assets held for sale. |
(2) |
In connection with the acquisition discussed in Note 4, Cenovus was deemed to have disposed of its pre-existing interest in FCCL and
re-acquired it at fair value as required by IFRS 3, which is not reflected in the table above. The carrying value of the pre-existing interest was $9,081 million
and the estimated fair value was $11,605 million as at May 17, 2017. |
2. BASIS OF PREPARATION AND
STATEMENT OF COMPLIANCE
In these interim
Consolidated Financial Statements, unless otherwise indicated, all dollars are expressed in Canadian dollars. All references to C$ or $ are to Canadian dollars and references to US$ are to U.S. dollars.
These interim Consolidated Financial Statements have been prepared in accordance with International Financial Reporting Standards (IFRS) as
issued by the International Accounting Standards Board (IASB) applicable to the preparation of interim financial statements, including International Accounting Standard 34, Interim Financial Reporting (IAS
34).
Certain information provided for the prior year has been reclassified to conform to the presentation adopted for the period ended
September 30, 2017.
These interim Consolidated Financial Statements were approved by the Audit Committee effective November 1, 2017.
3. SIGNIFICANT ACCOUNTING POLICIES
A) Accounting Policies
Certain information and disclosures normally included in the notes to the annual Consolidated Financial Statements have been condensed or have been
disclosed on an annual basis only. Accordingly, these interim Consolidated Financial Statements should be read in conjunction with the annual Consolidated Financial Statements for the year ended December 31, 2016, which have been prepared
in accordance with IFRS as issued by the IASB. These interim Consolidated Financial Statements have been prepared following the same accounting policies and methods of computation as the annual Consolidated Financial Statements for the year ended
December 31, 2016, except for income taxes. Clarification on our business combinations and goodwill accounting policy has been added below.
Income Taxes
Income taxes on earnings or loss in interim periods are accrued using the income tax rate that
would be applicable to the expected total annual earnings or loss.
Business Combinations and Goodwill
Business combinations are accounted for using the acquisition method of accounting in which the identifiable assets acquired, liabilities assumed and non-controlling interest, if any, 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 cash-generating units (CGUs) to which it relates. Subsequent measurement of goodwill is
at cost less any accumulated impairment losses.
|
|
|
Cenovus Energy Inc.
Third Quarter 2017 Report |
|
Page 64
Notes to Consolidated Financial Statements |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
All amounts in $ millions, unless otherwise indicated
For the period ended September 30, 2017
A contingent payment transferred in a business combination is measured at fair value on the date of
acquisition and classified as a financial liability or equity. A contingent payment classified as a liability is re-measured at fair value at each reporting date, with changes in fair value recognized in net
earnings. Payments are classified as cash used in investing activities until the cumulative payments exceed the acquisition date fair value of the liability. Cumulative payments in excess of the acquisition date fair value are classified as cash
used in operating activities. Contingent payments classified as equity are not re-measured and settlements are accounted for within equity.
When a business combination is achieved in stages, the Company re-measures its
pre-existing interest at the acquisition date fair value and recognizes the resulting gain or loss, if any, in net earnings.
B) Recent Accounting Pronouncements
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 after
January 1, 2017 and have not been applied in preparing the Consolidated Financial Statements for the period ended September 30, 2017. The following provides an update to the disclosure in the annual Consolidated Financial
Statements for the year ended December 31, 2016.
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. The standard may be applied retrospectively or using the
retrospective with cumulative effect approach. The Company is currently evaluating the impact of adopting IFRS 15 on the Consolidated Financial Statements and plans to adopt the standard for its year ended December 31, 2018.
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 has been adopted. The standard may be applied retrospectively or using a modified retrospective approach. The modified retrospective approach does
not require restatement of prior period financial information as it recognizes the cumulative effect as an adjustment to opening retained earnings and applies the standard prospectively.
The Company plans to apply IFRS 16 on January 1, 2019. A transition team is assessing the impacts of adopting IFRS 16 and will oversee
changes to accounting systems, processes and internal controls. The estimated time and effort necessary to develop and implement required changes (including the impact to information technology systems) extends into 2018. Although the transition
approach on adoption has not yet been determined, it is anticipated that the adoption of IFRS 16 will have a material impact on the Consolidated Balance Sheets.
C) 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. Further to those areas discussed in the annual
Consolidated Financial Statements for the year ended December 31, 2016, the estimation of fair values of the assets acquired and liabilities assumed in a business combination, including contingent payment and goodwill, is a key area
involving significant estimates or judgments.
|
|
|
Cenovus Energy Inc.
Third Quarter 2017 Report |
|
Page 65
Notes to Consolidated Financial Statements |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
All amounts in $ millions, unless otherwise indicated
For the period ended September 30, 2017
4. ACQUISITION
A) Summary of the Acquisition
On March 29, 2017, Cenovus entered into a purchase and sale agreement with ConocoPhillips to acquire ConocoPhillips
50 percent interest in FCCL and the majority of ConocoPhillips Deep Basin Assets in Alberta and British Columbia (the Acquisition). The Acquisition was completed on May 17, 2017, with an effective date of
January 1, 2017.
The Acquisition provides Cenovus with control over the Companys oil sands operations, doubles the Companys oil
sands production, and almost doubles the Companys proved bitumen reserves. The Deep Basin Assets provide a second core operating area with more than three million net acres of land, exploration and production assets, and related infrastructure
in Alberta and British Columbia.
The Acquisition has been accounted for using the acquisition method pursuant to IFRS 3, Business
Combinations (IFRS 3). Under the acquisition method, assets and liabilities are recorded at their fair values on the date of acquisition and the total consideration is allocated to the tangible and intangible assets
acquired and liabilities assumed. The excess of consideration given over the fair value of the net assets acquired has been recorded as goodwill.
B) Identifiable Assets Acquired and Liabilities Assumed
The preliminary purchase price allocation is based on
Managements best estimate of fair value. Upon finalizing the fair value of net assets acquired, adjustments to initial estimates, including goodwill, may be required. No significant adjustments were made to the preliminary purchase price
allocation as at September 30, 2017.
The following table summarizes the recognized amounts of assets acquired and liabilities assumed at the
date of the Acquisition.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
May 17, |
|
As at |
|
Notes |
|
|
2017 |
|
|
|
|
100 Percent of the Identifiable Assets Acquired and Liabilities Assumed for
FCCL |
|
|
|
|
|
|
|
|
Cash |
|
|
|
|
|
|
880 |
|
Accounts Receivable and Accrued Revenues |
|
|
|
|
|
|
964 |
|
Inventories |
|
|
|
|
|
|
303 |
|
E&E Assets |
|
|
12 |
|
|
|
918 |
|
PP&E |
|
|
13 |
|
|
|
22,290 |
|
Other Assets |
|
|
|
|
|
|
6 |
|
Accounts Payable and Accrued Liabilities |
|
|
|
|
|
|
(445) |
|
Decommissioning Liabilities |
|
|
17 |
|
|
|
(277) |
|
Other Liabilities |
|
|
|
|
|
|
(8) |
|
Deferred Income Taxes |
|
|
|
|
|
|
(2,497) |
|
|
|
|
|
|
|
|
22,134 |
|
Recognized Amounts of Identifiable Assets Acquired and Liabilities Assumed for Deep
Basin |
|
|
|
|
|
|
|
|
Accounts Receivable and Accrued Revenues |
|
|
|
|
|
|
16 |
|
Inventories |
|
|
|
|
|
|
2 |
|
E&E Assets |
|
|
12 |
|
|
|
3,639 |
|
PP&E |
|
|
13 |
|
|
|
3,049 |
|
Accounts Payable and Accrued Liabilities |
|
|
|
|
|
|
(12) |
|
Decommissioning Liabilities |
|
|
17 |
|
|
|
(667) |
|
|
|
|
|
|
|
|
6,027 |
|
Total Identifiable Net Assets |
|
|
|
|
|
|
28,161 |
|
The fair value of acquired accounts receivables and accrued revenues was $980 million, the majority of which has been collected.
|
|
|
Cenovus Energy Inc.
Third Quarter 2017 Report |
|
Page 66
Notes to Consolidated Financial Statements |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
All amounts in $ millions, unless otherwise indicated
For the period ended September 30, 2017
C) Total Consideration
Total consideration for the Acquisition consisted of US$10.6 billion in cash and 208 million Cenovus common shares plus closing adjustments. At
the same time, Cenovus agreed to make certain quarterly contingent payments to ConocoPhillips during the five years subsequent to May 17, 2017 if crude oil prices exceed a specific threshold. The following table summarizes the fair value
of the consideration:
|
|
|
|
|
As at |
|
May 17, 2017 |
|
|
|
Common Shares |
|
|
2,579 |
|
Cash |
|
|
15,002 |
|
|
|
|
17,581 |
|
Estimated Contingent Payment (Note 15) |
|
|
361 |
|
Total Consideration |
|
|
17,942 |
|
At the date of closing, the Company issued 208 million common shares to ConocoPhillips that were accounted for at
$12.40 per share, the estimated fair value for accounting purposes.
Consideration paid in cash was US$10.6 billion, before closing
adjustments, and was financed through a bought-deal common share offering (see Note 19) and an offering in the United States for senior unsecured notes (see Note 16). In addition, Cenovus borrowed $3.6 billion under a committed asset
sale bridge credit facility. The remainder of the cash purchase price was funded with cash on hand and a draw on Cenovuss existing committed credit facility.
The estimated contingent payment related to oil sands production reflects that Cenovus agreed to make quarterly payments to ConocoPhillips during the five
years subsequent to the closing date for quarters in which the average Western Canadian Select (WCS) crude oil price exceeds $52.00 per barrel during the quarter. The quarterly payment will be $6 million for each dollar that
the WCS price exceeds $52.00 per barrel. There are no maximum payment terms.
The calculation of any contingent payment includes an
adjustment mechanism related to certain significant production outages at Foster Creek and Christina Lake, which may reduce the amount of a contingent payment. The terms of the contingent payment agreement allow Cenovus to retain 80 percent to
85 percent of the WCS prices above $52.00 per barrel, based on current gross production capacity at Foster Creek and Christina Lake. As production capacity increases with future expansions, the percentage of upside available to
Cenovus will increase further.
The contingent payment is accounted for as a financial option. The fair value of $361 million on
May 17, 2017 was estimated by calculating the present value of the future expected cash flows using an option pricing model, which assumes the probability distribution for WCS is based on the volatility of West Texas Intermediate
(WTI) options, volatility of Canadian-U.S. foreign exchange rate options and WCS futures pricing, and discounted at a credit-adjusted risk-free rate of 2.9 percent. The contingent payment will
be re-measured at fair value at each reporting date with changes in fair value recognized in net earnings (see Note 15).
D) Goodwill
Goodwill arising from the Acquisition has been recognized as follows:
|
|
|
|
|
|
|
|
|
As at |
|
Notes |
|
|
May 17, 2017 |
|
|
|
|
Total Purchase Consideration |
|
|
4C |
|
|
|
17,942 |
|
Fair Value of Pre-Existing 50 Percent Ownership Interest in
FCCL |
|
|
|
|
|
|
12,316 |
|
Fair Value of Identifiable Net Assets |
|
|
4B |
|
|
|
(28,161) |
|
Goodwill |
|
|
|
|
|
|
2,097 |
|
Fair Value of Pre-Existing 50 Percent Ownership Interest in FCCL
Prior to the Acquisition, Cenovuss 50 percent interest in FCCL was jointly controlled with ConocoPhillips and met the
definition of a joint operation under IFRS 11, Joint Arrangements and as such Cenovus recognized its share of the assets, liabilities, revenues and expenses in its consolidated results. Subsequent to Acquisition, Cenovus controls
FCCL, as defined under IFRS 10, Consolidated Financial Statements and accordingly, FCCL has been consolidated. As required by IFRS 3, when an acquirer achieves control in stages, the previously held interest is re-measured to fair value at the acquisition date with any gain or loss recognized in net earnings. The acquisition-date fair value of the previously held interest was $12.3 billion and has been included in the
measurement of the total consideration transferred. Cenovus recognized a non-cash revaluation gain of $2.5 billion ($1.8 billion, after-tax) on the re-measurement to fair value of its existing interest in FCCL.
|
|
|
Cenovus Energy Inc.
Third Quarter 2017 Report |
|
Page 67
Notes to Consolidated Financial Statements |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
All amounts in $ millions, unless otherwise indicated
For the period ended September 30, 2017
Goodwill was recorded in connection with deferred tax liabilities arising from the difference between
the purchase price allocated to the FCCL assets and liabilities based on fair value and the tax basis of these assets and liabilities. In addition, the consideration paid for FCCL included a control premium, which resulted in a higher value compared
to the fair value of the net assets acquired.
E) Acquisition-Related Costs
The Company incurred $56 million of Acquisition-related costs, excluding common share and debt issuance costs. These costs have been included in
transaction costs in the Consolidated Statements of Earnings.
Debt issuance costs related to the Acquisition financing were $71 million. These
costs are netted against the carrying amount of the debt and amortized using the effective interest method.
F) Transitional
Services
Under the purchase and sales agreement, Cenovus and ConocoPhillips agreed to certain transitional services where ConocoPhillips
will provide certain day-to-day services required by Cenovus for a period of approximately nine months. These transactions are in the normal course of operations and are
measured at the exchange amounts.
In the nine months ended September 30, 2017, costs related to the transitional services of approximately
$28 million were recorded in general and administrative expenses.
G) Revenue and Profit Contribution
The acquired business contributed revenues of $1.9 billion and net earnings of $141 million for the period from May 17, 2017 to
September 30, 2017.
If the closing of the Acquisition had occurred on January 1, 2017, Cenovuss consolidated pro forma
revenue and net earnings for the nine months ended September 30, 2017 would have been $14.0 billion and $2.9 billion, respectively. These amounts have been calculated using results from the acquired business and adjusting them
for:
|
· |
|
Differences in accounting policies, |
|
· |
|
Additional finance costs that would have been incurred if the amounts drawn on the Companys committed asset sale
bridge credit facility and the senior unsecured notes issued to fund the Acquisition had occurred on January 1, 2017, |
|
· |
|
Additional depreciation, depletion and amortization (DD&A) that would have been charged assuming the fair
value adjustments to PP&E and E&E assets had applied from January 1, 2017, |
|
· |
|
Accretion on the decommissioning liability if it had been assumed on January 1, 2017, and
|
|
· |
|
The consequential tax effects. |
This pro forma information is not necessarily indicative of the results that would have been obtained if the Acquisition had actually occurred on
January 1, 2017.
5. FINANCE COSTS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
Nine Months Ended |
For the periods ended September 30, |
|
2017 |
|
|
|
2016 |
|
|
|
2017 |
|
|
|
2016 |
|
|
|
|
|
|
|
|
Interest Expense Short-Term Borrowings and Long-Term Debt |
|
168 |
|
|
|
84 |
|
|
|
405 |
|
|
|
255 |
Unwinding of Discount on Decommissioning Liabilities (Note 17) |
|
16 |
|
|
|
8 |
|
|
|
32 |
|
|
|
21 |
Other |
|
7 |
|
|
|
5 |
|
|
|
21 |
|
|
|
16 |
|
|
191 |
|
|
|
97 |
|
|
|
458 |
|
|
|
292 |
6. FOREIGN EXCHANGE (GAIN) LOSS, NET |
|
|
Three Months Ended |
|
|
|
Nine Months Ended |
For the periods ended September 30, |
|
2017 |
|
|
|
2016 |
|
|
|
2017 |
|
|
|
2016 |
|
|
|
|
|
|
|
|
Unrealized Foreign Exchange (Gain) Loss on Translation of: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Dollar Debt Issued From Canada |
|
(380) |
|
|
|
52 |
|
|
|
(715) |
|
|
|
(343) |
Other |
|
(60) |
|
|
|
(2) |
|
|
|
(193) |
|
|
|
2 |
Unrealized Foreign Exchange (Gain) Loss |
|
(440) |
|
|
|
50 |
|
|
|
(908) |
|
|
|
(341) |
Realized Foreign Exchange (Gain) Loss |
|
90 |
|
|
|
(5) |
|
|
|
72 |
|
|
|
3 |
|
|
(350) |
|
|
|
45 |
|
|
|
(836) |
|
|
|
(338) |
|
|
|
Cenovus Energy Inc.
Third Quarter 2017 Report |
|
Page 68
Notes to Consolidated Financial Statements |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
All amounts in $ millions, unless otherwise indicated
For the period ended September 30, 2017
7. IMPAIRMENT CHARGES
A) Cash-Generating Unit
Impairments
2017 Impairments
As at September 30, 2017, there were no CGU impairments.
For the purpose of impairment testing, goodwill is allocated to the CGU to which it relates. There were no goodwill impairments for the nine months ended
September 30, 2017.
2016 Upstream Impairments
Due to a decline in forward commodity prices as at September 30, 2016, the Company tested its upstream CGUs for impairment. The Company determined
that the carrying amount of the Northern Alberta and Suffield CGUs exceeded their recoverable amounts, resulting in an impairment loss of $210 million and $65 million, respectively. The Company had previously impaired the Northern Alberta
CGU by $170 million at March 31, 2016 due to the decline in forward heavy crude oil prices. The impairment was recorded as additional DD&A in the Conventional segment, which has been classified as a discontinued operation.
As at September 30, 2016, the recoverable amount of the Northern Alberta and Suffield CGUs were estimated to be approximately $1.1 billion
and $483 million, respectively, based on the fair value less costs of disposal. The fair values for producing properties were calculated based on discounted after-tax cash flows of proved and probable
reserves using forward prices and cost estimates, prepared by Cenovuss independent qualified reserves evaluators (Level 3). Future cash flows were estimated using a two percent inflation rate and discounted using a rate of 10 percent.
Forward prices as at September 30, 2016 used to determine future cash flows from crude oil and natural gas reserves were:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Remainder of 2016 |
|
2017 |
|
2018 |
|
2019 |
|
2020 |
|
Average
Annual % Change to 2026 |
WTI (US$/barrel) |
|
50.00 |
|
53.50 |
|
59.70 |
|
66.10 |
|
70.00 |
|
3.6% |
WCS (C$/barrel) |
|
45.50 |
|
50.90 |
|
57.00 |
|
63.50 |
|
65.20 |
|
3.2% |
AECO (C$/Mcf) (1) (2) |
|
2.95 |
|
3.00 |
|
3.15 |
|
3.45 |
|
3.60 |
|
3.6% |
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
Alberta Energy Company (AECO) natural gas. |
(2) |
Assumes gas heating value of one million British Thermal Units per thousand cubic feet. |
There were no impairments of goodwill for the nine months ended September 30, 2016.
B) Asset Impairment
For the nine months ended September 30, 2017, $3 million of previously capitalized E&E costs were deemed not to be technically feasible
and commercially viable. An impairment loss of $1 million was recorded as exploration expense in the Oil Sands segment and the remainder was recorded in the Conventional segment, which has been classified as a discontinued operation.
For the three months ended September 30, 2016, the Company recorded an impairment loss of $16 million related to preliminary engineering costs
associated with a project that was cancelled and equipment that was written down to its recoverable amount. This impairment loss was recorded as additional DD&A in the Oil Sands segment. In the second quarter of 2016, $4 million of
leasehold improvements were written off. This impairment loss was recorded as additional DD&A in the Corporate and Eliminations segment.
8.
ASSETS HELD FOR SALE AND DISCONTINUED OPERATIONS
Concurrent with the announcement of the Acquisition on March 29, 2017, Cenovus commenced marketing for sale certain
non-core properties comprising its Pelican Lake heavy oil assets, including the adjacent Grand Rapids project in the Greater Pelican Lake region, and its Suffield crude oil and natural gas assets. On
June 20, 2017, the Company announced its intent to divest the remainder of its Conventional segment assets, including its Palliser asset in southern Alberta and its Weyburn oil operation in southern Saskatchewan. As a result, the Conventional
segment has been classified as held for sale and a discontinued operation. The assets have been recorded at the lesser of their carrying amount and their fair value less costs to sell. No impairments were recorded on the assets held for sale as at
September 30, 2017.
|
|
|
Cenovus Energy Inc.
Third Quarter 2017 Report |
|
Page 69
Notes to Consolidated Financial Statements |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
All amounts in $ millions, unless otherwise indicated
For the period ended September 30, 2017
A) Results of Discontinued Operations
On September 29, 2017, the Company completed the sale of its Pelican Lake heavy oil operations, as well as other miscellaneous assets in northern
Alberta, for cash proceeds of $975 million before closing adjustments. Net proceeds from the sale were applied against the Companys $3.6 billion asset-sale bridge facility. A before tax loss on discontinuance of $603 million (after-tax loss $440 million) was recorded on the sale.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
Nine Months Ended |
For the periods ended September 30, |
|
2017 |
|
|
|
2016 |
|
|
|
2017 |
|
|
|
2016 |
|
|
|
|
|
|
|
|
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross Sales |
|
331 |
|
|
|
330 |
|
|
|
1,091 |
|
|
|
898 |
Less: Royalties |
|
45 |
|
|
|
35 |
|
|
|
145 |
|
|
|
88 |
|
|
286 |
|
|
|
295 |
|
|
|
946 |
|
|
|
810 |
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transportation and Blending |
|
44 |
|
|
|
44 |
|
|
|
149 |
|
|
|
136 |
Operating |
|
118 |
|
|
|
102 |
|
|
|
343 |
|
|
|
331 |
Production and Mineral Taxes |
|
4 |
|
|
|
4 |
|
|
|
14 |
|
|
|
9 |
(Gain) Loss on Risk Management |
|
3 |
|
|
|
(7) |
|
|
|
19 |
|
|
|
(57) |
Operating Margin |
|
117 |
|
|
|
152 |
|
|
|
421 |
|
|
|
391 |
Depreciation, Depletion and Amortization |
|
- |
|
|
|
412 |
|
|
|
190 |
|
|
|
877 |
Exploration Expense |
|
- |
|
|
|
- |
|
|
|
2 |
|
|
|
- |
Finance Costs |
|
3 |
|
|
|
25 |
|
|
|
36 |
|
|
|
76 |
Earnings (Loss) From Discontinued Operations Before Income Tax |
|
114 |
|
|
|
(285) |
|
|
|
193 |
|
|
|
(562) |
Current Tax Expense (Recovery) |
|
2 |
|
|
|
26 |
|
|
|
24 |
|
|
|
86 |
Deferred Tax Expense (Recovery) |
|
29 |
|
|
|
(115) |
|
|
|
27 |
|
|
|
(262) |
After-tax Earnings (Loss) From Discontinued
Operations |
|
83 |
|
|
|
(196) |
|
|
|
142 |
|
|
|
(386) |
After-tax Loss on Discontinuance (1) |
|
(440) |
|
|
|
- |
|
|
|
(440) |
|
|
|
- |
Net Earnings (Loss) From Discontinued Operations |
|
(357) |
|
|
|
(196) |
|
|
|
(298) |
|
|
|
(386) |
(1) |
Net of a $163 million deferred tax recovery. |
B) Assets and Liabilities Held for Sale
As at
September 30, 2017, the assets and liabilities held for sale relate to the Suffield and Palliser areas in Alberta and the Weyburn area in Saskatchewan. See Note 27 for further information on the divestiture of these assets.
|
|
|
|
|
As at September 30, 2017 |
|
Total |
|
|
|
E&E Assets (Note 12) |
|
|
11 |
|
PP&E (Note 13) |
|
|
1,794 |
|
Decommissioning Liabilities (Note 17) |
|
|
1,318 |
|
C) Cash Flows From Discontinued Operations
Cash flows from discontinued operations reported in the consolidated statement of cash flows are:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
Nine Months Ended |
For the periods ended September 30, |
|
2017 |
|
|
|
2016 |
|
|
|
2017 |
|
|
|
2016 |
|
|
|
|
|
|
|
|
Cash From Operating Activities |
|
111 |
|
|
|
121 |
|
|
|
381 |
|
|
|
293 |
Cash From (Used in) Investing Activities |
|
897 |
|
|
|
(38) |
|
|
|
759 |
|
|
|
(111) |
Net Cash Flow |
|
1,008 |
|
|
|
83 |
|
|
|
1,140 |
|
|
|
182 |
|
|
|
Cenovus Energy Inc.
Third Quarter 2017 Report |
|
Page 70
Notes to Consolidated Financial Statements |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
All amounts in $ millions, unless otherwise indicated
For the period ended September 30, 2017
9. INCOME TAXES
The provision for income taxes is:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
Nine Months Ended |
For the periods ended September 30, |
|
2017 |
|
|
|
2016 |
|
|
|
2017 |
|
|
|
2016 |
|
|
|
|
|
|
|
|
Current Tax |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada |
|
(23) |
|
|
|
(71) |
|
|
|
(232) |
|
|
|
(187) |
United States |
|
(39) |
|
|
|
- |
|
|
|
(40) |
|
|
|
1 |
Total Current Tax Expense (Recovery) |
|
(62) |
|
|
|
(71) |
|
|
|
(272) |
|
|
|
(186) |
Deferred Tax Expense (Recovery) |
|
(48) |
|
|
|
5 |
|
|
|
893 |
|
|
|
(91) |
Tax Expense (Recovery) From Continuing Operations |
|
(110) |
|
|
|
(66) |
|
|
|
621 |
|
|
|
(277) |
The following table reconciles income taxes calculated at the Canadian statutory rate with recorded income taxes:
|
|
|
|
|
|
|
|
|
Nine Months Ended |
For the periods ended September 30, |
|
2017 |
|
|
|
2016 |
|
|
|
|
Earnings (Loss) From Continuing Operations Before Income Tax |
|
3,701 |
|
|
|
(527) |
Canadian Statutory Rate |
|
27.0% |
|
|
|
27.0% |
Expected Income Tax (Recovery) |
|
999 |
|
|
|
(142) |
Effect of Taxes Resulting From: |
|
|
|
|
|
|
Foreign Tax Rate Differential |
|
(31) |
|
|
|
(38) |
Non-Taxable Capital (Gains) Losses |
|
(148) |
|
|
|
(46) |
Non-Recognition of Capital (Gains) Losses |
|
(121) |
|
|
|
(46) |
Adjustments Arising from Prior Year Tax Filings |
|
(36) |
|
|
|
(48) |
Recognition of Previously Unrecognized Capital Losses |
|
(65) |
|
|
|
- |
Non-Deductible Expenses |
|
3 |
|
|
|
6 |
Other |
|
20 |
|
|
|
37 |
Tax Expense (Recovery) From Continuing Operations |
|
621 |
|
|
|
(277) |
Effective Tax Rate |
|
16.8% |
|
|
|
52.6% |
10. PER SHARE AMOUNTS
A) Net Earnings (Loss) Per Share
Basic and Diluted
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
Nine Months Ended |
For the periods ended September 30, |
|
2017 |
|
|
|
2016 |
|
|
|
2017 |
|
|
|
2016 |
|
|
|
|
|
|
|
|
Earnings (Loss) From: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Continuing Operations |
|
288 |
|
|
|
(55) |
|
|
|
3,080 |
|
|
|
(250) |
Discontinued Operations |
|
(357) |
|
|
|
(196) |
|
|
|
(298) |
|
|
|
(386) |
Net Earnings (Loss) |
|
(69) |
|
|
|
(251) |
|
|
|
2,782 |
|
|
|
(636) |
|
|
|
|
|
|
|
|
Weighted Average Number of Shares (millions) |
|
1,228.8 |
|
|
|
833.3 |
|
|
|
1,059.9 |
|
|
|
833.3 |
|
|
|
|
|
|
|
|
Basic and Diluted Earnings (Loss) Per Share From: ($) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Continuing Operations |
|
0.23 |
|
|
|
(0.07) |
|
|
|
2.91 |
|
|
|
(0.30) |
Discontinued Operations |
|
(0.29) |
|
|
|
(0.23) |
|
|
|
(0.29) |
|
|
|
(0.46) |
Net Earnings (Loss) Per Share |
|
(0.06) |
|
|
|
(0.30) |
|
|
|
2.62 |
|
|
|
(0.76) |
B) Dividends Per Share
For the nine months ended September 30, 2017, the Company paid dividends of $164 million or $0.15 per share (nine months ended
September 30, 2016 $124 million or $0.15 per share).
|
|
|
Cenovus Energy Inc.
Third Quarter 2017 Report |
|
Page 71
Notes to Consolidated Financial Statements |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
All amounts in $ millions, unless otherwise indicated
For the period ended September 30, 2017
11. INVENTORIES
Cenovus recorded a $3 million write-down of product
inventories to net realizable value as at September 30, 2017. As at December 31, 2016, Cenovus recorded a $4 million write-down of its product inventory.
12. EXPLORATION AND EVALUATION ASSETS
|
|
|
|
|
|
|
Total |
|
|
As at December 31, 2016 |
|
1,585 |
Additions |
|
128 |
Acquisition (Note 4) (1) |
|
4,557 |
Transfers to Assets Held for Sale (Note 8) |
|
(269) |
Exploration Expense (Note 7) |
|
(3) |
Change in Decommissioning Liabilities |
|
(2) |
Divestitures (1) |
|
(479) |
As at September 30, 2017 |
|
5,517 |
(1) |
In connection with the Acquisition, Cenovus was deemed to have disposed of its pre-existing interest in FCCL and re-acquired it at fair
value as required by IFRS 3. |
13. PROPERTY, PLANT AND EQUIPMENT, NET
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Upstream Assets |
|
|
|
|
|
|
|
|
|
|
|
|
Development & Production |
|
|
|
Other Upstream |
|
|
|
Refining Equipment |
|
|
|
Other (1) |
|
|
|
Total |
|
|
|
|
|
|
|
|
|
|
COST |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As at December 31, 2016 |
|
31,941 |
|
|
|
333 |
|
|
|
5,259 |
|
|
|
1,074 |
|
|
|
38,607 |
Additions |
|
798 |
|
|
|
- |
|
|
|
120 |
|
|
|
41 |
|
|
|
959 |
Acquisition (Note 4) (2) |
|
25,339 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
25,339 |
Transfers to Assets Held for Sale (Note 8) |
|
(19,249) |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(19,249) |
Change in Decommissioning Liabilities |
|
(105) |
|
|
|
- |
|
|
|
2 |
|
|
|
(2) |
|
|
|
(105) |
Exchange Rate Movements and Other |
|
(1) |
|
|
|
- |
|
|
|
(386) |
|
|
|
- |
|
|
|
(387) |
Divestitures (2) |
|
(12,267) |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(12,267) |
As at September 30, 2017 |
|
26,456 |
|
|
|
333 |
|
|
|
4,995 |
|
|
|
1,113 |
|
|
|
32,897 |
|
ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION |
As at December 31, 2016 |
|
20,088 |
|
|
|
308 |
|
|
|
1,076 |
|
|
|
709 |
|
|
|
22,181 |
DD&A |
|
1,145 |
|
|
|
18 |
|
|
|
157 |
|
|
|
51 |
|
|
|
1,371 |
Transfers to Assets Held for Sale (Note 8) |
|
(16,084) |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(16,084) |
Exchange Rate Movements and Other |
|
(3) |
|
|
|
- |
|
|
|
(93) |
|
|
|
- |
|
|
|
(96) |
Divestitures (2) |
|
(3,610) |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(3,610) |
As at September 30, 2017 |
|
1,536 |
|
|
|
326 |
|
|
|
1,140 |
|
|
|
760 |
|
|
|
3,762 |
|
|
|
|
|
|
|
|
|
|
CARRYING VALUE |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As at December 31, 2016 |
|
11,853 |
|
|
|
25 |
|
|
|
4,183 |
|
|
|
365 |
|
|
|
16,426 |
As at September 30, 2017 |
|
24,920 |
|
|
|
7 |
|
|
|
3,855 |
|
|
|
353 |
|
|
|
29,135 |
(1) |
Includes crude-by-rail terminal, office furniture, fixtures, leasehold improvements, information technology and aircraft.
|
(2) |
In connection with the Acquisition, Cenovus was deemed to have disposed of its pre-existing interest in FCCL and re-acquired it at fair
value as required by IFRS 3. |
|
|
|
Cenovus Energy Inc.
Third Quarter 2017 Report |
|
Page 72
Notes to Consolidated Financial Statements |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
All amounts in $ millions, unless otherwise indicated
For the period ended September 30, 2017
14. GOODWILL
|
|
|
|
|
|
|
|
|
September 30, |
|
|
|
December 31, |
As at |
|
2017 |
|
|
|
2016 |
Carrying Value, Beginning of Period |
|
242 |
|
|
|
242 |
Goodwill Recognized on Acquisition (Note 4) |
|
2,097 |
|
|
|
- |
Carrying Value, End of Period |
|
2,339 |
|
|
|
242 |
The carrying amount of goodwill allocated to the Companys exploration and production CGUs is:
|
|
|
|
|
|
|
As at |
|
September 30, 2017 |
|
|
|
December 31, 2016 |
|
|
|
|
Primrose (Foster Creek) |
|
1,106 |
|
|
|
242 |
Christina Lake |
|
1,032 |
|
|
|
- |
Narrows Lake |
|
201 |
|
|
|
- |
|
|
2,339 |
|
|
|
242 |
15. CONTINGENT PAYMENT
|
|
|
|
|
|
|
|
|
|
|
|
Total |
As at January 1, 2017 |
|
|
|
|
|
- |
Initial Recognition on May 17, 2017 (Note 4) |
|
|
|
|
|
361 |
Re-measurement (1)
|
|
|
|
|
|
(109) |
Payments |
|
|
|
|
|
- |
As at September 30, 2017 |
|
|
|
|
|
252 |
(1) |
Contingent payment is carried at fair value. Changes in fair value are recorded in net earnings. |
In connection with the Acquisition (see Note 4), Cenovus agreed to make quarterly payments to ConocoPhillips during the five years subsequent to
May 17, 2017 for quarters in which the average WCS crude oil price exceeds $52.00 per barrel during the quarter. The quarterly payment will be $6 million for each dollar that the WCS price exceeds $52.00 per barrel.
There are no maximum payment terms. From May 17, 2017 to September 30, 2017, WCS averaged less than $52 per barrel; therefore, no amount was payable.
The calculation includes an adjustment mechanism related to certain significant production outages at Foster Creek and Christina Lake which may reduce the
amount of a contingent payment.
16. LONG-TERM DEBT
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As at |
|
|
|
|
US$ Principal Amount September 30, 2017 |
|
|
|
September 30, 2017 |
|
|
|
December 31, 2016 |
|
|
|
|
|
|
|
Revolving Term Debt (1) |
|
|
A |
|
|
- |
|
|
|
- |
|
|
|
- |
Asset Sale Bridge Credit Facility |
|
|
B |
|
|
- |
|
|
|
2,650 |
|
|
|
- |
U.S. Dollar Denominated Unsecured Notes |
|
|
C |
|
|
7,650 |
|
|
|
9,547 |
|
|
|
6,378 |
Total Debt Principal |
|
|
|
|
|
|
|
|
|
12,197 |
|
|
|
6,378 |
Debt Discounts and Transaction Costs |
|
|
|
|
|
|
|
|
|
(103) |
|
|
|
(46) |
Long-Term Debt |
|
|
|
|
|
|
|
|
|
12,094 |
|
|
|
6,332 |
(1) |
Revolving term debt may include Bankers Acceptances, London Interbank Offered Rate based loans, prime rate loans and U.S. base rate loans. |
Consideration for the Acquisition (see Note 4) was partially financed through borrowings under the Companys committed asset sale bridge credit
facility and an offering in the United States for senior unsecured notes, as well as its existing committed credit facility.
|
|
|
Cenovus Energy Inc.
Third Quarter 2017 Report |
|
Page 73
Notes to Consolidated Financial Statements |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
All amounts in $ millions, unless otherwise indicated
For the period ended September 30, 2017
A) Revolving Term Debt
On April 28, 2017, Cenovus amended its existing committed credit facility to increase the capacity of the facility by $0.5 billion to
$4.5 billion and to extend the maturity dates. The committed credit facility consists of a $1.2 billion tranche maturing on November 30, 2020 and a $3.3 billion tranche maturing on November 30, 2021. As at
September 30, 2017, Cenovus had $4.5 billion available on its committed credit facility.
B) Asset Sale Bridge Credit Facility
In connection with the Acquisition, Cenovus borrowed $3.6 billion under a committed asset sale bridge credit facility. On
September 29, 2017, the Company repaid $950 million using proceeds from the sale of certain assets, retiring the first tranche of the facility and a portion of the second tranche. As at September 30, 2017, a $1.75 billion tranche
maturing on November 17, 2018 and a $0.9 billion tranche maturing on May 17, 2019 remain outstanding. Cenovus expects to repay the remaining tranches through the sale of additional assets (see Note 8).
C) Unsecured Notes
On
April 7, 2017, Cenovus completed an offering in the United States for US$2.9 billion in senior unsecured notes in three series (collectively, the 2017 Notes), as follows:
|
|
|
|
|
|
|
As at |
|
US$ Principal
Amount |
|
|
|
September 30,
2017 |
|
|
|
|
4.25% due 2027 |
|
1,200 |
|
|
|
1,498 |
5.25% due 2037 |
|
700 |
|
|
|
873 |
5.40% due 2047 |
|
1,000 |
|
|
|
1,248 |
|
|
2,900 |
|
|
|
3,619 |
In connection with the offering of the 2017 Notes, Cenovus agreed to make an exchange offer (the Exchange
Offering) for the 2017 Notes whereby the holders will be entitled to exchange the 2017 Notes for new notes with the same terms and provisions, except that the new notes will not be subject to transfer restrictions.
On October 10, 2017, Cenovus filed a base shelf prospectus that allows the Company to offer, from time to time, up to US$7.5 billion, or
the equivalent in other currencies, of debt securities, common shares, preferred shares, subscription receipts, warrants, share purchase contracts and units in Canada, the U.S. and elsewhere where permitted by law. The base shelf prospectus also
allows Cenovus to conduct the Exchange Offering and ConocoPhillips to offer, should they so choose from time to time, the common shares they acquired in connection with the Acquisition. The base shelf prospectus will expire in November 2019 and
replaces the Companys US$5.0 billion base shelf prospectus, which would have expired in March 2018. Offerings under the base shelf prospectus are subject to market conditions.
As at September 30, 2017, the Company is in compliance with all of the terms of its debt agreements.
17. 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:
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
As at December 31, 2016 |
|
|
|
|
|
1,847 |
Liabilities Incurred |
|
|
|
|
|
6 |
Liabilities Acquired (Note 4) (1) |
|
|
|
|
|
944 |
Liabilities Settled |
|
|
|
|
|
(47) |
Liabilities Divested (1) |
|
|
|
|
|
(138) |
Transfers to Liabilities Related to Assets Held for Sale (Note 8) |
|
|
|
|
|
(1,455) |
Change in Estimated Future Cash Flows |
|
|
|
|
|
(15) |
Change in Discount Rate |
|
|
|
|
|
(98) |
Unwinding of Discount on Decommissioning Liabilities |
|
|
|
|
|
68 |
Foreign Currency Translation |
|
|
|
|
|
(3) |
As at September 30, 2017 |
|
|
|
|
|
1,109 |
(1) |
In connection with the Acquisition, Cenovus was deemed to have disposed of its pre-existing interest in FCCL and reacquired it at fair value as required by IFRS.
|
|
|
|
Cenovus Energy Inc.
Third Quarter 2017 Report |
|
Page 74
Notes to Consolidated Financial Statements |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
All amounts in $ millions, unless otherwise indicated
For the period ended September 30, 2017
The undiscounted amount of estimated future cash flows required to settle the obligation has been
discounted using a credit-adjusted risk-free rate of 6.0 percent as at September 30, 2017 (December 31,
2016 5.9 percent).
18. OTHER LIABILITIES
|
|
|
|
|
|
|
|
|
September 30, |
|
|
|
December 31, |
As at |
|
2017 |
|
|
|
2016 |
|
|
|
|
Employee Long-Term Incentives |
|
39 |
|
|
|
72 |
Pension and Other Post-Employment Benefit Plan |
|
76 |
|
|
|
71 |
Onerous Contract Provisions |
|
36 |
|
|
|
35 |
Other |
|
33 |
|
|
|
33 |
|
|
184 |
|
|
|
211 |
19. SHARE CAPITAL
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2017 |
|
|
|
December 31, 2016 |
As at |
|
Number of Common Shares
(thousands) |
|
|
|
Amount |
|
|
|
Number of Common Shares
(thousands) |
|
|
|
Amount |
|
|
|
|
|
|
|
|
Outstanding, Beginning of Period |
|
833,290 |
|
|
|
5,534 |
|
|
|
833,290 |
|
|
|
5,534 |
Common Shares Issued, Net of Issuance Costs and Tax |
|
187,500 |
|
|
|
2,927 |
|
|
|
- |
|
|
|
- |
Common Shares Issued to ConocoPhillips |
|
208,000 |
|
|
|
2,579 |
|
|
|
- |
|
|
|
- |
Outstanding, End of Period |
|
1,228,790 |
|
|
|
11,040 |
|
|
|
833,290 |
|
|
|
5,534 |
In connection with the Acquisition (see Note 4), Cenovus closed a bought-deal common share financing on
April 6, 2017 for 187.5 million common shares, raising gross proceeds of $3.0 billion ($2.9 billion net of $101 million of share issuance costs).
In addition, the Company issued 208 million common shares to ConocoPhillips on May 17, 2017 as partial consideration for the Acquisition.
In relation to the share consideration, Cenovus and ConocoPhillips entered into an investor agreement, and a registration rights agreement which, among other things, restricts ConocoPhillips from selling or hedging its Cenovus common shares until
November 17, 2017. ConocoPhillips is also restricted from nominating new members to Cenovuss Board of Directors and must vote its Cenovus common shares in accordance with Management recommendations or abstain from voting until such
time ConocoPhillips owns 3.5 percent or less of the then outstanding common shares of Cenovus.
There were no preferred shares outstanding as at
September 30, 2017 (December 31, 2016 nil).
As at September 30, 2017, there were 15 million
(December 31, 2016 12 million) common shares available for future issuance under the stock option plan.
|
|
|
Cenovus Energy Inc.
Third Quarter 2017 Report |
|
Page 75
Notes to Consolidated Financial Statements |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
All amounts in $ millions, unless otherwise indicated
For the period ended September 30, 2017
20. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Defined
Benefit Pension Plan |
|
|
|
Foreign
Currency
Translation Adjustment |
|
|
|
Available
for Sale
Financial
Assets |
|
|
|
Total |
|
|
|
|
|
|
|
|
As at December 31, 2015 |
|
(10) |
|
|
|
1,014 |
|
|
|
16 |
|
|
|
1,020 |
Other Comprehensive Income (Loss), Before Tax |
|
(13) |
|
|
|
(205) |
|
|
|
(4) |
|
|
|
(222) |
Income Tax |
|
4 |
|
|
|
- |
|
|
|
3 |
|
|
|
7 |
As at September 30, 2016 |
|
(19) |
|
|
|
809 |
|
|
|
15 |
|
|
|
805 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As at December 31, 2016 |
|
(13) |
|
|
|
908 |
|
|
|
15 |
|
|
|
910 |
Other Comprehensive Income (Loss), Before Tax |
|
1 |
|
|
|
(290) |
|
|
|
(1) |
|
|
|
(290) |
Income Tax |
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
As at September 30, 2017 |
|
(12) |
|
|
|
618 |
|
|
|
14 |
|
|
|
620 |
21. STOCK-BASED COMPENSATION PLANS
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). The following table summarizes information related to Cenovuss stock-based compensation plans:
|
|
|
|
|
|
|
As at September 30, 2017 |
|
Units
Outstanding
(thousands) |
|
|
|
Units
Exercisable
(thousands) |
|
|
|
|
NSRs |
|
42,710 |
|
|
|
36,172 |
TSARs |
|
154 |
|
|
|
154 |
PSUs |
|
7,021 |
|
|
|
- |
RSUs |
|
6,883 |
|
|
|
- |
DSUs |
|
1,633 |
|
|
|
1,633 |
|
|
|
|
For the nine months ended September 30, 2017 |
|
Units
Granted
(thousands) |
|
|
|
Units
Vested and
Paid Out
(thousands) |
|
|
|
|
NSRs |
|
2,822 |
|
|
|
- |
PSUs |
|
2,228 |
|
|
|
451 |
RSUs |
|
3,263 |
|
|
|
101 |
DSUs |
|
126 |
|
|
|
112 |
Certain directors, officers or employees chose prior to December 31, 2016 to convert a portion of their
remuneration, paid in the first quarter of 2017, into DSUs. The election for any particular year is irrevocable. DSUs may not be redeemed until departure from the Company. Directors also received an annual grant of DSUs.
The weighted average exercise price of NSRs and TSARs as at September 30, 2017 was $29.68 and $31.78, respectively.
The following table summarizes the stock-based compensation expense (recovery) recorded for all plans:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
Nine Months Ended |
For the periods ended September 30, |
|
2017 |
|
|
|
2016 |
|
|
|
2017 |
|
|
|
2016 |
|
|
|
|
|
|
|
|
NSRs |
|
1 |
|
|
|
4 |
|
|
|
7 |
|
|
|
12 |
PSUs |
|
12 |
|
|
|
7 |
|
|
|
- |
|
|
|
7 |
RSUs |
|
9 |
|
|
|
3 |
|
|
|
3 |
|
|
|
8 |
DSUs |
|
6 |
|
|
|
2 |
|
|
|
(11) |
|
|
|
4 |
Stock-Based Compensation Expense (Recovery) |
|
28 |
|
|
|
16 |
|
|
|
(1) |
|
|
|
31 |
Stock-Based Compensation Costs Capitalized |
|
9 |
|
|
|
4 |
|
|
|
5 |
|
|
|
8 |
Total Stock-Based Compensation |
|
37 |
|
|
|
20 |
|
|
|
4 |
|
|
|
39 |
|
|
|
Cenovus Energy Inc.
Third Quarter 2017 Report |
|
Page 76
Notes to Consolidated Financial Statements |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
All amounts in $ millions, unless otherwise indicated
For the period ended September 30, 2017
22. CAPITAL STRUCTURE
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, and the current and long-term portions of long-term debt, 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
measures consisting of Debt to Capitalization and Debt to Adjusted Earnings Before Interest, Taxes and DD&A (Adjusted EBITDA). These measures 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 |
|
September 30, 2017 |
|
|
|
December 31, 2016 |
|
|
|
|
Debt |
|
12,094 |
|
|
|
6,332 |
Shareholders Equity |
|
19,433 |
|
|
|
11,590 |
|
|
31,527 |
|
|
|
17,922 |
Debt to Capitalization |
|
38% |
|
|
|
35% |
|
|
|
|
Debt |
|
12,094 |
|
|
|
6,332 |
Add (Deduct): |
|
|
|
|
|
|
Cash and Cash Equivalents |
|
(632) |
|
|
|
(3,720) |
Net Debt |
|
11,462 |
|
|
|
2,612 |
Shareholders Equity |
|
19,433 |
|
|
|
11,590 |
|
|
30,895 |
|
|
|
14,202 |
Net Debt to Capitalization |
|
37% |
|
|
|
18% |
B) Debt to Adjusted EBITDA and Net Debt to
Adjusted EBITDA |
As at |
|
September 30,
2017 |
|
|
|
December 31, 2016 |
|
|
|
|
Debt |
|
12,094 |
|
|
|
6,332 |
Net Debt |
|
11,462 |
|
|
|
2,612 |
|
|
|
|
Net Earnings (Loss) |
|
2,873 |
|
|
|
(545) |
Add (Deduct): |
|
|
|
|
|
|
Finance Costs |
|
618 |
|
|
|
492 |
Interest Income |
|
(66) |
|
|
|
(52) |
Income Tax Expense (Recovery) |
|
580 |
|
|
|
(382) |
DD&A |
|
1,300 |
|
|
|
1,498 |
E&E Impairment |
|
3 |
|
|
|
2 |
Unrealized (Gain) Loss on Risk Management |
|
189 |
|
|
|
554 |
Foreign Exchange (Gain) Loss, Net |
|
(696) |
|
|
|
(198) |
Revaluation (Gain) |
|
(2,524) |
|
|
|
- |
Re-measurement of Contingent Payment |
|
(109) |
|
|
|
- |
Loss on Discontinuance |
|
603 |
|
|
|
- |
(Gain) Loss on Divestitures of Assets |
|
- |
|
|
|
6 |
Other (Income) Loss, Net |
|
23 |
|
|
|
34 |
Adjusted EBITDA (1) |
|
2,794 |
|
|
|
1,409 |
|
|
|
|
Debt to Adjusted EBITDA |
|
4.3x |
|
|
|
4.5x |
Net Debt to Adjusted EBITDA |
|
4.1x |
|
|
|
1.9x |
(1) |
Calculated on a trailing twelve-month basis. Includes discontinued operations. |
|
|
|
Cenovus Energy Inc.
Third Quarter 2017 Report |
|
Page 77
Notes to Consolidated Financial Statements |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
All amounts in $ millions, unless otherwise indicated
For the period ended September 30, 2017
As at September 30, 2017, Cenovuss debt to adjusted EBITDA and net debt to adjusted
EBITDA are 4.3x and 4.1x, respectively. These ratios are well outside of the Companys target range. However, it is important to note that adjusted EBITDA is calculated on a rolling twelve-month basis and as such, only includes the financial
results from the Deep Basin Assets and the additional 50 percent of FCCL for the period May 17, 2017 to September 30, 2017. Debt and net debt are presented as at September 30, 2017; therefore, the ratios are fully
burdened by the debt issued to finance the Acquisition. If adjusted EBITDA reflected a full twelve months of earnings from the acquired assets, Cenovuss debt and net debt to adjusted EBITDA ratios would be substantially lower.
Cenovus will maintain a high level of capital discipline and manage its capital structure to help 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 facility or repay existing debt.
Cenovus has in place a committed credit facility that consists of a
$1.2 billion tranche maturing on November 30, 2020 and a $3.3 billion tranche maturing on November 30, 2021. As at September 30, 2017, Cenovus had $4.5 billion available on its committed credit facility.
Under the committed credit facility, the Company is required to maintain a debt to capitalization ratio, as defined in the agreement, not to exceed 65 percent. The Company is well below this limit.
On October 10, 2017, Cenovus filed a US$7.5 billion base shelf prospectus. The base shelf prospectus expires in November 2019 and replaces the
Companys previous base shelf prospectus, which would have expired in March 2018. Offerings under the base shelf prospectus are subject to market conditions.
As at September 30, 2017, Cenovus is in compliance with all of the terms of its debt agreements.
23. FINANCIAL INSTRUMENTS
Cenovuss 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, contingent
payment, 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 these 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 September 30, 2017, the carrying value of Cenovuss debt was $12,094 million and the fair
value was $12,371 million (December 31, 2016 carrying value $6,332 million, fair value $6,539 million).
Available for sale
financial assets comprise private equity investments. These 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:
|
|
|
|
|
|
|
Total |
|
|
As at December 31, 2016 |
|
35 |
Acquisition of Investments |
|
2 |
Change in Fair Value (1) |
|
(1) |
As at September 30, 2017 |
|
36 |
(1) |
Changes in fair value on available for sale financial assets are recorded in other comprehensive income. |
|
|
|
Cenovus Energy Inc.
Third Quarter 2017 Report |
|
Page 78
Notes to Consolidated Financial Statements |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
All amounts in $ millions, unless otherwise indicated
For the period ended September 30, 2017
B) Fair Value of Risk Management Assets and Liabilities
The Companys risk management assets and liabilities consist of crude oil swaps and options, as well as condensate, natural gas and 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 interest rate swaps are calculated using
external valuation models which incorporate observable market data, including interest rate yield curves (Level 2).
Summary of
Unrealized Risk Management Positions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2017 |
|
|
|
December 31, 2016 |
|
|
Risk Management |
|
Risk Management |
As at |
|
Asset |
|
|
|
Liability |
|
|
|
Net |
|
|
|
Asset |
|
|
|
Liability |
|
|
|
Net |
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil |
|
35 |
|
|
|
333 |
|
|
|
(298) |
|
|
|
21 |
|
|
|
307 |
|
|
|
(286) |
Interest Rate |
|
2 |
|
|
|
17 |
|
|
|
(15) |
|
|
|
3 |
|
|
|
8 |
|
|
|
(5) |
Total Fair Value |
|
37 |
|
|
|
350 |
|
|
|
(313) |
|
|
|
24 |
|
|
|
315 |
|
|
|
(291) |
The following table presents the Companys fair value hierarchy for risk management assets and liabilities carried at fair value:
|
|
|
|
|
|
|
As at |
|
September 30, 2017 |
|
|
|
December 31, 2016 |
|
|
|
|
Level 2 Prices Sourced From Observable Data or Market Corroboration |
|
(313) |
|
|
|
(291) |
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.
The following table provides a reconciliation of changes in the fair value of
Cenovuss risk management assets and liabilities from January 1 to September 30:
|
|
|
|
|
|
|
|
|
2017 |
|
|
|
2016 |
|
|
|
|
Fair Value of Contracts, Beginning of Year |
|
(291) |
|
|
|
271 |
Fair Value of Contracts Realized During the Period (1)
|
|
(47) |
|
|
|
(199) |
Change in Fair Value of Contracts in Place at Beginning of Year and Contracts Entered Into During the
Period |
|
(28) |
|
|
|
(241) |
Unamortized Premium on Put Options |
|
33 |
|
|
|
- |
Unrealized Foreign Exchange Gain (Loss) on U.S. Dollar Contracts |
|
20 |
|
|
|
(12) |
Fair Value of Contracts, End of Period |
|
(313) |
|
|
|
(181) |
(1) |
Includes realized loss of $19 million in 2017 related to the Conventional segment which is included in Discontinued Operations. |
C) Fair Value of Contingent Payment
The contingent payment is carried at fair value on the Consolidated Balance Sheets. Fair value is estimated by calculating the present value of the future
expected cash flows using an option pricing model (Level 3), which assumes the probability distribution for WCS is based on the volatility of WTI options, volatility of Canadian-U.S. foreign exchange rate
options and WCS futures pricing, and discounted at a credit-adjusted risk-free rate of 3.7 percent. Fair value of the contingent payment has been calculated by Cenovuss internal valuation team which consists of individuals who are
knowledgeable and have experience in fair value techniques. As at September 30, 2017, the fair value of contingent payment was estimated to be $252 million.
As at September 30, 2017, average WCS forward pricing for the remaining term of the contingent payment is US$35.51 per barrel or
C$44.28 per barrel. The average volatility of WTI options and the Canadian-U.S. foreign exchange rates was 24 percent and nine percent, respectively. Changes in the following inputs to the
option pricing model, with fluctuations in all other variables held constant, could have resulted in unrealized gains (losses) impacting earnings before income tax as follows:
|
|
|
|
|
|
|
|
|
|
|
Sensitivity Range |
|
Increase |
|
|
|
Decrease |
|
|
|
|
|
WCS Forward Prices |
|
± $5.00 per bbl |
|
(218) |
|
|
|
151 |
WTI Option Volatility |
|
± five percent |
|
(27) |
|
|
|
22 |
U.S. to Canadian Dollar Foreign Exchange Rate Volatility |
|
± five percent |
|
2 |
|
|
|
(1) |
|
|
|
Cenovus Energy Inc.
Third Quarter 2017 Report |
|
Page 79
Notes to Consolidated Financial Statements |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
All amounts in $ millions, unless otherwise indicated
For the period ended September 30, 2017
D) Earnings Impact of (Gains) Losses From Risk Management Positions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
Nine Months Ended |
|
For the periods ended September 30, |
|
2017 |
|
|
|
2016 |
|
|
|
2017 |
|
|
|
2016 |
|
|
|
|
|
|
|
|
|
Realized (Gain) Loss (1) |
|
10 |
|
|
|
(34) |
|
|
|
(66) |
|
|
|
|
(142 |
) |
Unrealized (Gain) Loss (2) |
|
486 |
|
|
|
7 |
|
|
|
75 |
|
|
|
|
440 |
|
(Gain) Loss on Risk Management |
|
496 |
|
|
|
(27) |
|
|
|
9 |
|
|
|
|
298 |
|
(1) |
Realized gains and losses on risk management are recorded in the reportable segment to which the derivative instrument
relates. Excludes realized risk management losses of $19 million in the nine months ended September 30, 2017 (nine months ended September 30, 2016 $57 million gain) that were classified as discontinued operations.
|
(2) |
Unrealized gains and losses on risk management are recorded in the Corporate and Eliminations segment.
|
24. RISK MANAGEMENT
Cenovus 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 description of the nature and extent of risks arising from the Companys financial assets and liabilities can be found
in the notes to the annual Consolidated Financial Statements as at December 31, 2016. Exposure to these risks has not changed significantly since December 31, 2016. To manage exposure to interest rate volatility, the Company entered
into interest rate swap contracts related to expected future debt issuances. As at September 30, 2017, Cenovus had a notional amount of US$400 million in interest rate swaps. To mitigate the Companys exposure to foreign exchange
rate fluctuations, the Company periodically enters into foreign exchange contracts.
Net Fair Value of Risk Management Positions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As at September 30, 2017 |
|
Notional Volumes |
|
|
|
|
|
Terms |
|
|
|
|
|
Average Price |
|
|
|
|
|
Fair Value |
|
|
|
|
|
|
|
|
|
Crude Oil Contracts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed Price Contracts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Brent Fixed Price |
|
|
108,000 bbls/d |
|
|
|
|
|
|
|
July December 2017 |
|
|
|
|
|
|
|
US$51.68/bbl |
|
|
|
|
|
|
|
(61 |
) |
Brent Fixed Price |
|
|
36,000 bbls/d |
|
|
|
|
|
|
|
August December 2017 |
|
|
|
|
|
|
|
US$49.90/bbl |
|
|
|
|
|
|
|
(28 |
) |
Brent Fixed Price |
|
|
60,000 bbls/d |
|
|
|
|
|
|
|
January June 2018 |
|
|
|
|
|
|
|
US$53.34/bbl |
|
|
|
|
|
|
|
(37 |
) |
WTI Fixed Price |
|
|
150,000 bbls/d |
|
|
|
|
|
|
|
January June 2018 |
|
|
|
|
|
|
|
US$48.91/bbl |
|
|
|
|
|
|
|
(108 |
) |
WTI Fixed Price |
|
|
75,000 bbls/d |
|
|
|
|
|
|
|
July December 2018 |
|
|
|
|
|
|
|
US$49.32/bbl |
|
|
|
|
|
|
|
(39 |
) |
Brent-WTI Differential |
|
|
50,000 bbls/d |
|
|
|
|
|
|
|
July December 2017 |
|
|
|
|
|
|
|
US$(1.88)/bbl |
|
|
|
|
|
|
|
(16 |
) |
|
|
|
|
|
|
|
|
Brent Put Options |
|
|
55,000 bbls/d |
|
|
|
|
|
|
|
July December 2017 |
|
|
|
|
|
|
|
US$53.00/bbl |
|
|
|
|
|
|
|
4 |
|
|
|
|
|
|
|
|
|
Brent Put Options |
|
|
25,000 bbls/d |
|
|
|
|
|
|
|
January June 2018 |
|
|
|
|
|
|
|
US$53.00/bbl |
|
|
|
|
|
|
|
16 |
|
|
|
|
|
|
|
|
|
Brent Collars |
|
|
80,000 bbls/d |
|
|
|
|
|
|
|
January June 2018 |
|
|
|
|
|
|
|
US$49.54 US$59.86/bbl |
|
|
|
|
|
|
|
(14 |
) |
WTI Collars |
|
|
50,000 bbls/d |
|
|
|
|
|
|
|
July December 2017 |
|
|
|
|
|
|
|
US$44.84 US$56.47/bbl |
|
|
|
|
|
|
|
(2 |
) |
|
|
|
|
|
|
|
|
WTI Collars |
|
|
10,000 bbls/d |
|
|
|
|
|
|
|
January June 2018 |
|
|
|
|
|
|
|
US$45.30 US$62.77/bbl |
|
|
|
|
|
|
|
2 |
|
WCS Differential |
|
|
16,000 bbls/d |
|
|
|
|
|
|
|
January March 2018 |
|
|
|
|
|
|
|
US$(13.11)/bbl |
|
|
|
|
|
|
|
1 |
|
WCS Differential |
|
|
15,000 bbls/d |
|
|
|
|
|
|
|
April June 2018 |
|
|
|
|
|
|
|
US$(14.05)/bbl |
|
|
|
|
|
|
|
- |
|
Other Financial Positions (1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(16 |
) |
Crude Oil Fair Value Position |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(298 |
) |
|
|
|
|
|
|
|
|
Natural Gas Contracts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed Price Contracts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NYMEX Fixed Price |
|
|
30 mmcf/d |
|
|
|
|
|
|
|
July December 2017 |
|
|
|
|
|
|
|
US$3.16/Mcf |
|
|
|
|
|
|
|
- |
|
NYMEX Fixed Price |
|
|
99 mmcf/d |
|
|
|
|
|
|
|
August December 2017 |
|
|
|
|
|
|
|
US$3.11/Mcf |
|
|
|
|
|
|
|
- |
|
NYMEX Fixed Price |
|
|
69 mmcf/d |
|
|
|
|
|
|
|
September December 2017 |
|
|
|
|
|
|
|
US$3.09/Mcf |
|
|
|
|
|
|
|
- |
|
NYMEX Fixed Price |
|
|
2 mmcf/d |
|
|
|
|
|
|
|
October December 2017 |
|
|
|
|
|
|
|
US$3.25/Mcf |
|
|
|
|
|
|
|
- |
|
|
|
|
|
|
|
|
|
Interest Rate Swaps |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(15 |
) |
|
|
|
|
|
|
|
|
Total Fair Value |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(313 |
) |
(1) |
Other financial positions are part of ongoing operations to market the Companys production. |
|
|
|
Cenovus Energy Inc.
Third Quarter 2017 Report |
|
Page 80
Notes to Consolidated Financial Statements |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
All amounts in $ millions, unless otherwise indicated
For the period ended September 30, 2017
Sensitivities Risk Management Positions
The following table summarizes the sensitivity of the fair value of Cenovuss risk management positions to fluctuations in commodity prices and
interest rates, with all other variables held constant. Management believes the 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 could have resulted in unrealized gains (losses) impacting earnings before income tax as follows:
Risk Management Positions in Place as at September 30, 2017
|
|
|
|
|
|
|
|
|
|
|
Sensitivity Range |
|
Increase |
|
|
|
Decrease |
|
|
|
|
|
Crude Oil Commodity Price |
|
± US$5.00 per bbl Applied to Brent, WTI and Condensate Hedges |
|
(511) |
|
|
|
515 |
Crude Oil Differential Price |
|
± US$2.50 per bbl Applied to Differential Hedges Tied to Production |
|
3 |
|
|
|
(3) |
Crude Oil Differential Price |
|
± US$1.00 per bbl Applied to Brent-WTI Differential |
|
6 |
|
|
|
(6) |
Natural Gas Commodity Price |
|
± US$1.00 per Mcf Applied to NYMEX and AECO Gas Hedges |
|
(23) |
|
|
|
23 |
Interest Rate Swaps |
|
± 50 Basis Points |
|
43 |
|
|
|
(50) |
25. SUPPLEMENTARY CASH FLOW INFORMATION
The following table provides a reconciliation of cash flows
arising from financing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends Payable |
|
|
|
Current Portion of Long-Term Debt |
|
|
|
Long-Term Debt |
|
|
|
Share Capital |
|
|
|
|
|
|
|
|
As at December 31, 2015 |
|
- |
|
|
|
- |
|
|
|
6,525 |
|
|
|
5,534 |
Changes From Financing Cash Flows: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends Paid |
|
(124) |
|
|
|
- |
|
|
|
- |
|
|
|
- |
Non-Cash Changes: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends Declared |
|
124 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
Unrealized Foreign Exchange (Gain) Loss (Note 6) |
|
- |
|
|
|
- |
|
|
|
(343) |
|
|
|
- |
Other |
|
- |
|
|
|
- |
|
|
|
2 |
|
|
|
- |
As at September 30, 2016 |
|
- |
|
|
|
- |
|
|
|
6,184 |
|
|
|
5,534 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As at December 31, 2016 |
|
- |
|
|
|
- |
|
|
|
6,332 |
|
|
|
5,534 |
Changes From Financing Cash Flows: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of Long-Term Debt |
|
- |
|
|
|
- |
|
|
|
3,842 |
|
|
|
- |
Net Issuance (Repayment) of Revolving Long-Term Debt |
|
- |
|
|
|
- |
|
|
|
33 |
|
|
|
- |
Issuance of Debt Under Asset Sale Bridge Facility |
|
- |
|
|
|
892 |
|
|
|
2,677 |
|
|
|
- |
(Repayment) of Debt Under Asset Sale Bridge Facility |
|
- |
|
|
|
(900) |
|
|
|
(50) |
|
|
|
- |
Common Shares Issued, Net of Issuance Costs |
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
2,899 |
Dividends Paid |
|
(164) |
|
|
|
- |
|
|
|
- |
|
|
|
- |
Non-Cash Changes: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common Shares Issued to ConocoPhillips |
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
2,579 |
Deferred Taxes on Share Issuance Costs |
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
28 |
Dividends Declared |
|
164 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
Unrealized Foreign Exchange (Gain) Loss |
|
- |
|
|
|
- |
|
|
|
(748) |
|
|
|
- |
Finance Costs |
|
- |
|
|
|
8 |
|
|
|
9 |
|
|
|
- |
Other |
|
- |
|
|
|
- |
|
|
|
(1) |
|
|
|
- |
As at September 30, 2017 |
|
- |
|
|
|
- |
|
|
|
12,094 |
|
|
|
11,040 |
|
|
|
Cenovus Energy Inc.
Third Quarter 2017 Report |
|
Page 81
Notes to Consolidated Financial Statements |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
All amounts in $ millions, unless otherwise indicated
For the period ended September 30, 2017
26. COMMITMENTS AND CONTINGENCIES
A) Commitments
Cenovus has entered into various commitments in the normal course of operations primarily related to demand charges on firm transportation agreements. In
addition, the Company has commitments related to its risk management program and an obligation to fund its defined benefit pension and other post-employment benefit plans. Additional information related to the Companys commitments can be found
in the notes to the annual Consolidated Financial Statements for the year ended December 31, 2016.
As at September 30, 2017,
total commitments were $20.7 billion, of which $17.2 billion were for various transportation commitments. During the nine months ended September 30, 2017, the Companys transportation commitments decreased by approximately
$9.1 billion primarily due to the Companys withdrawal from certain transportation initiatives including the cancellation of the Energy East pipeline, and use of contracts partially offset by new firm transportation agreements. In relation
to the Acquisition, the Company assumed $3.7 billion of commitments primarily consisting of transportation commitments on various pipelines.
Transportation commitments include $7.5 billion that are subject to regulatory approval or have been approved but are not yet in service
(December 31, 2016 $19.2 billion). Terms are up to 20 years subsequent to the date of commencement and should help align the Companys future transportation requirements with anticipated production growth.
As at September 30, 2017, there were outstanding letters of credit aggregating $257 million issued as security for performance under
certain contracts (December 31, 2016 $258 million).
B) Contingencies
Legal Proceedings
Cenovus is involved in a limited number of legal claims associated with the normal course of operations. Cenovus believes that any liabilities that might
arise from such matters, to the extent not provided for, are not likely to have a material effect on its Consolidated Financial Statements.
Contingent Payment
In connection with the Acquisition, Cenovus agreed to make quarterly payments to
ConocoPhillips during the five years subsequent to May 17, 2017 for quarters in which the average WCS crude oil price exceeds $52.00 per barrel during the quarter. As at September 30, 2017, the estimated fair value of the
contingent payment was $252 million (see Note 15).
27. SUBSEQUENT EVENTS
A) Suffield Divestiture
On September 25, 2017, Cenovus entered into an agreement to sell its Suffield crude oil and natural gas operations in southern
Alberta for gross cash proceeds of $512 million. The agreement includes a deferred purchase price adjustment (DPPA) that could provide Cenovus with purchase price adjustments of up to $36 million if the average crude oil and
natural gas prices rise over the next two years.
The DPPA is a two year agreement that commences January 1, 2018. Under the purchase and sale
agreement, Cenovus is entitled to receive cash for each month in which the average daily price of WTI is above US$55 per barrel or the price of Henry Hub natural gas is above US$3.50 per million British thermal units. The monthly DPPAs are capped at
$375 thousand and $1.125 million for crude oil and natural gas, respectively. The DPPA will be accounted for as a financial option and fair valued at each reporting date. The fair value of the DPPA on the date of close will be included in
proceeds received to determine the gain on the divestiture. As at September 30, 2017, the fair value of the DPPA was estimated to be between $5 million and $10 million. Excluding the DPPA, the Company anticipates a gain of
approximately $340 million.
The sale of the Suffield assets is expected to close in the fourth quarter of 2017, subject to closing conditions.
Net proceeds will be applied to reduce the Companys outstanding asset sale bridge credit facility.
B) Palliser Divestiture
On October 19, 2017, Cenovus entered into an agreement to sell its Palliser crude oil and natural gas operations in southern Alberta
for gross cash proceeds of $1.3 billion. The Company anticipates a gain of approximately $1.6 billion, after the derecognition of associated decommissioning liabilities. The sale of the Palliser assets is expected to close in the fourth
quarter of 2017, subject to closing conditions. Net proceeds will be applied to reduce the Companys outstanding asset sale bridge credit facility.
|
|
|
Cenovus Energy Inc.
Third Quarter 2017 Report |
|
Page 82
Notes to Consolidated Financial Statements |
SUPPLEMENTAL INFORMATION (unaudited)
Financial Statistics
($ millions, except per share amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2017 |
|
|
2016 |
|
Revenues |
|
|
YTD |
|
|
|
Q3 |
|
|
|
Q2 |
|
|
|
Q1 |
|
|
|
Year |
|
|
|
Q4 |
|
|
|
Q3 YTD |
|
|
|
Q3 |
|
|
|
Q2 |
|
|
|
Q1 |
|
Gross Sales |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil Sands |
|
|
4,938 |
|
|
|
2,210 |
|
|
|
1,666 |
|
|
|
1,062 |
|
|
|
2,929 |
|
|
|
957 |
|
|
|
1,972 |
|
|
|
793 |
|
|
|
709 |
|
|
|
470 |
|
Deep Basin |
|
|
324 |
|
|
|
200 |
|
|
|
124 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Refining and Marketing |
|
|
7,162 |
|
|
|
2,161 |
|
|
|
2,397 |
|
|
|
2,604 |
|
|
|
8,439 |
|
|
|
2,477 |
|
|
|
5,962 |
|
|
|
2,245 |
|
|
|
2,129 |
|
|
|
1,588 |
|
Corporate and Eliminations |
|
|
(322 |
) |
|
|
(118 |
) |
|
|
(106 |
) |
|
|
(98 |
) |
|
|
(353 |
) |
|
|
(108 |
) |
|
|
(245 |
) |
|
|
(89 |
) |
|
|
(89 |
) |
|
|
(67 |
) |
Less: Royalties |
|
|
138 |
|
|
|
67 |
|
|
|
44 |
|
|
|
27 |
|
|
|
9 |
|
|
|
2 |
|
|
|
7 |
|
|
|
4 |
|
|
|
3 |
|
|
|
- |
|
Revenues from Continuing Operations |
|
|
11,964 |
|
|
|
4,386 |
|
|
|
4,037 |
|
|
|
3,541 |
|
|
|
11,006 |
|
|
|
3,324 |
|
|
|
7,682 |
|
|
|
2,945 |
|
|
|
2,746 |
|
|
|
1,991 |
|
Conventional (Net of Royalties) - Discontinued
Operations |
|
|
946 |
|
|
|
286 |
|
|
|
336 |
|
|
|
324 |
|
|
|
1,128 |
|
|
|
318 |
|
|
|
810 |
|
|
|
295 |
|
|
|
261 |
|
|
|
254 |
|
Total Revenues |
|
|
12,910 |
|
|
|
4,672 |
|
|
|
4,373 |
|
|
|
3,865 |
|
|
|
12,134 |
|
|
|
3,642 |
|
|
|
8,492 |
|
|
|
3,240 |
|
|
|
3,007 |
|
|
|
2,245 |
|
|
|
|
|
|
2017 |
|
|
2016 |
|
Operating Margin (1) |
|
|
YTD |
|
|
|
Q3 |
|
|
|
Q2 |
|
|
|
Q1 |
|
|
|
Year |
|
|
|
Q4 |
|
|
|
Q3 YTD |
|
|
|
Q3 |
|
|
|
Q2 |
|
|
|
Q1 |
|
Oil Sands |
|
|
1,620 |
|
|
|
824 |
|
|
|
544 |
|
|
|
252 |
|
|
|
877 |
|
|
|
334 |
|
|
|
543 |
|
|
|
267 |
|
|
|
231 |
|
|
|
45 |
|
Deep Basin |
|
|
119 |
|
|
|
64 |
|
|
|
55 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
|
1,739 |
|
|
|
888 |
|
|
|
599 |
|
|
|
252 |
|
|
|
877 |
|
|
|
334 |
|
|
|
543 |
|
|
|
267 |
|
|
|
231 |
|
|
|
45 |
|
Refining and Marketing |
|
|
284 |
|
|
|
211 |
|
|
|
20 |
|
|
|
53 |
|
|
|
346 |
|
|
|
108 |
|
|
|
238 |
|
|
|
68 |
|
|
|
193 |
|
|
|
(23 |
) |
Operating Margin from Continuing Operations |
|
|
2,023 |
|
|
|
1,099 |
|
|
|
619 |
|
|
|
305 |
|
|
|
1,223 |
|
|
|
442 |
|
|
|
781 |
|
|
|
335 |
|
|
|
424 |
|
|
|
22 |
|
Conventional - Discontinued Operations |
|
|
421 |
|
|
|
117 |
|
|
|
159 |
|
|
|
145 |
|
|
|
544 |
|
|
|
153 |
|
|
|
391 |
|
|
|
152 |
|
|
|
117 |
|
|
|
122 |
|
Total Operating Margin |
|
|
2,444 |
|
|
|
1,216 |
|
|
|
778 |
|
|
|
450 |
|
|
|
1,767 |
|
|
|
595 |
|
|
|
1,172 |
|
|
|
487 |
|
|
|
541 |
|
|
|
144 |
|
|
|
|
|
|
2017 |
|
|
2016 |
|
Adjusted Funds Flow (2) |
|
|
YTD |
|
|
|
Q3 |
|
|
|
Q2 |
|
|
|
Q1 |
|
|
|
Year |
|
|
|
Q4 |
|
|
|
Q3 YTD |
|
|
|
Q3 |
|
|
|
Q2 |
|
|
|
Q1 |
|
Total Cash From Operating Activities |
|
|
2,159 |
|
|
|
592 |
|
|
|
1,239 |
|
|
|
328 |
|
|
|
861 |
|
|
|
164 |
|
|
|
697 |
|
|
|
310 |
|
|
|
205 |
|
|
|
182 |
|
Deduct (Add Back): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Change in Other Assets and Liabilities |
|
|
(75 |
) |
|
|
(19 |
) |
|
|
(25 |
) |
|
|
(31 |
) |
|
|
(91 |
) |
|
|
(32 |
) |
|
|
(59 |
) |
|
|
(13 |
) |
|
|
(17 |
) |
|
|
(29 |
) |
Net Change in Non-Cash Working Capital |
|
|
137 |
|
|
|
(371 |
) |
|
|
472 |
|
|
|
36 |
|
|
|
(471 |
) |
|
|
(339 |
) |
|
|
(132 |
) |
|
|
(99 |
) |
|
|
(218 |
) |
|
|
185 |
|
Total Adjusted Funds Flow |
|
|
2,097 |
|
|
|
982 |
|
|
|
792 |
|
|
|
323 |
|
|
|
1,423 |
|
|
|
535 |
|
|
|
888 |
|
|
|
422 |
|
|
|
440 |
|
|
|
26 |
|
Total Per Share - Basic and Diluted |
|
|
1.98 |
|
|
|
0.80 |
|
|
|
0.71 |
|
|
|
0.39 |
|
|
|
1.71 |
|
|
|
0.64 |
|
|
|
1.07 |
|
|
|
0.51 |
|
|
|
0.53 |
|
|
|
0.03 |
|
|
|
|
|
|
2017 |
|
|
2016 |
|
Earnings |
|
|
YTD |
|
|
|
Q3 |
|
|
|
Q2 |
|
|
|
Q1 |
|
|
|
Year |
|
|
|
Q4 |
|
|
|
Q3 YTD |
|
|
|
Q3 |
|
|
|
Q2 |
|
|
|
Q1 |
|
Operating Earnings (Loss) from Continuing Operations
(3) |
|
|
558 |
|
|
|
253 |
|
|
|
344 |
|
|
|
(39 |
) |
|
|
(291 |
) |
|
|
21 |
|
|
|
(312 |
) |
|
|
(40 |
) |
|
|
(3 |
) |
|
|
(269 |
) |
Per Share from Continuing Operations - Diluted |
|
|
0.53 |
|
|
|
0.21 |
|
|
|
0.31 |
|
|
|
(0.05 |
) |
|
|
(0.35 |
) |
|
|
0.03 |
|
|
|
(0.37 |
) |
|
|
(0.05 |
) |
|
|
- |
|
|
|
(0.32 |
) |
Total Operating Earnings (Loss) (3)
|
|
|
699 |
|
|
|
340 |
|
|
|
398 |
|
|
|
(39 |
) |
|
|
(377 |
) |
|
|
321 |
|
|
|
(698 |
) |
|
|
(236 |
) |
|
|
(39 |
) |
|
|
(423 |
) |
Total Per Share - Diluted |
|
|
0.66 |
|
|
|
0.28 |
|
|
|
0.36 |
|
|
|
(0.05 |
) |
|
|
(0.45 |
) |
|
|
0.39 |
|
|
|
(0.84 |
) |
|
|
(0.28 |
) |
|
|
(0.05 |
) |
|
|
(0.51 |
) |
Net Earnings (Loss) from Continuing Operations |
|
|
3,080 |
|
|
|
288 |
|
|
|
2,581 |
|
|
|
211 |
|
|
|
(459 |
) |
|
|
(209 |
) |
|
|
(250 |
) |
|
|
(55 |
) |
|
|
(231 |
) |
|
|
36 |
|
Per Share from Continuing Operations - Basic and Diluted |
|
|
2.91 |
|
|
|
0.23 |
|
|
|
2.32 |
|
|
|
0.25 |
|
|
|
(0.55 |
) |
|
|
(0.25 |
) |
|
|
(0.30 |
) |
|
|
(0.07 |
) |
|
|
(0.28 |
) |
|
|
0.04 |
|
Total Net Earnings (Loss) |
|
|
2,782 |
|
|
|
(69 |
) |
|
|
2,640 |
|
|
|
211 |
|
|
|
(545 |
) |
|
|
91 |
|
|
|
(636 |
) |
|
|
(251 |
) |
|
|
(267 |
) |
|
|
(118 |
) |
Total Per Share - Basic and Diluted |
|
|
2.62 |
|
|
|
(0.06 |
) |
|
|
2.37 |
|
|
|
0.25 |
|
|
|
(0.65 |
) |
|
|
0.11 |
|
|
|
(0.76 |
) |
|
|
(0.30 |
) |
|
|
(0.32 |
) |
|
|
(0.14 |
) |
|
|
|
|
|
2017 |
|
|
2016 |
|
Net Capital Investment ($
millions) |
|
|
YTD |
|
|
|
Q3 |
|
|
|
Q2 |
|
|
|
Q1 |
|
|
|
Year |
|
|
|
Q4 |
|
|
|
Q3 YTD |
|
|
|
Q3 |
|
|
|
Q2 |
|
|
|
Q1 |
|
Oil Sands |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foster Creek |
|
|
312 |
|
|
|
122 |
|
|
|
120 |
|
|
|
70 |
|
|
|
263 |
|
|
|
52 |
|
|
|
211 |
|
|
|
54 |
|
|
|
68 |
|
|
|
89 |
|
Christina Lake |
|
|
272 |
|
|
|
132 |
|
|
|
77 |
|
|
|
63 |
|
|
|
282 |
|
|
|
60 |
|
|
|
222 |
|
|
|
47 |
|
|
|
61 |
|
|
|
114 |
|
Other Oil Sands |
|
|
76 |
|
|
|
19 |
|
|
|
18 |
|
|
|
39 |
|
|
|
59 |
|
|
|
16 |
|
|
|
43 |
|
|
|
9 |
|
|
|
10 |
|
|
|
24 |
|
Total Oil Sands |
|
|
660 |
|
|
|
273 |
|
|
|
215 |
|
|
|
172 |
|
|
|
604 |
|
|
|
128 |
|
|
|
476 |
|
|
|
110 |
|
|
|
139 |
|
|
|
227 |
|
Deep Basin |
|
|
77 |
|
|
|
64 |
|
|
|
13 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
|
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Conventional |
|
|
180 |
|
|
|
42 |
|
|
|
50 |
|
|
|
88 |
|
|
|
171 |
|
|
|
57 |
|
|
|
114 |
|
|
|
41 |
|
|
|
34 |
|
|
|
39 |
|
Refining and Marketing |
|
|
124 |
|
|
|
38 |
|
|
|
40 |
|
|
|
46 |
|
|
|
220 |
|
|
|
64 |
|
|
|
156 |
|
|
|
51 |
|
|
|
53 |
|
|
|
52 |
|
Corporate |
|
|
37 |
|
|
|
21 |
|
|
|
9 |
|
|
|
7 |
|
|
|
31 |
|
|
|
10 |
|
|
|
21 |
|
|
|
6 |
|
|
|
10 |
|
|
|
5 |
|
Capital Investment |
|
|
1,078 |
|
|
|
438 |
|
|
|
327 |
|
|
|
313 |
|
|
|
1,026 |
|
|
|
259 |
|
|
|
767 |
|
|
|
208 |
|
|
|
236 |
|
|
|
323 |
|
Acquisitions (4) |
|
|
18,301 |
|
|
|
70 |
|
|
|
18,231 |
|
|
|
- |
|
|
|
11 |
|
|
|
- |
|
|
|
11 |
|
|
|
- |
|
|
|
11 |
|
|
|
- |
|
Divestitures
(4) |
|
|
(943 |
) |
|
|
(943 |
) |
|
|
- |
|
|
|
- |
|
|
|
(8 |
) |
|
|
- |
|
|
|
(8 |
) |
|
|
(8 |
) |
|
|
- |
|
|
|
- |
|
Net Acquisition and Divestiture Activity |
|
|
17,358 |
|
|
|
(873 |
) |
|
|
18,231 |
|
|
|
- |
|
|
|
3 |
|
|
|
- |
|
|
|
3 |
|
|
|
(8 |
) |
|
|
11 |
|
|
|
- |
|
Net Capital Investment |
|
|
18,436 |
|
|
|
(435 |
) |
|
|
18,558 |
|
|
|
313 |
|
|
|
1,029 |
|
|
|
259 |
|
|
|
770 |
|
|
|
200 |
|
|
|
247 |
|
|
|
323 |
|
(1) |
Operating Margin is an additional subtotal found in Note 1 of the Consolidated Financial Statements and is used to
provide a consistent measure of the cash generating performance of our assets for comparability of our underlying financial performance between periods. Operating Margin is defined as revenues less purchased product, transportation and blending,
operating expenses, production and mineral taxes plus realized gains less realized losses on risk management activities. Items within the Corporate and Eliminations segment are excluded from the calculation of Operating Margin.
|
(2) |
Adjusted Funds 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. Adjusted Funds Flow is defined as Cash From Operating Activities excluding net change in other assets and liabilities and
net change in non-cash working capital. Net change in other assets and liabilities is composed of site restoration costs and pension funding. Non-cash working capital is
composed of current assets and current liabilities, excluding cash and cash equivalents, risk management, the contingent payment, assets held for sale and liabilities related to assets held for sale. |
(3) |
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, revaluation gain, 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. |
(4) |
In connection with the Acquisition that was completed in the second quarter of 2017, Cenovus was deemed to have disposed
of its pre-existing interest in FCCL and re-acquired it at fair value as required by IFRS 3, which is not reflected in the table above. The carrying value of the pre-existing interest was $9,081 million and the fair value was $11,605 million as at May 17, 2017. |
|
|
|
Cenovus Energy Inc. Third Quarter 2017 Report |
|
Page 83 Supplemental
Information |
SUPPLEMENTAL INFORMATION (unaudited)
Financial Statistics (continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2017 |
|
2016 |
Financial Metrics (Non-GAAP Measures) |
|
|
YTD |
|
|
|
Q3 |
|
|
|
Q2 |
|
|
|
Q1 |
|
|
|
Year |
|
|
|
Q4 |
|
|
|
Q3 YTD |
|
|
|
Q3 |
|
|
|
Q2 |
|
|
|
Q1 |
|
Net Debt to Adjusted EBITDA (1) (3) |
|
|
4.1x |
|
|
|
4.1x |
|
|
|
6.1x |
|
|
|
1.6x |
|
|
|
1.9x |
|
|
|
1.9x |
|
|
|
2.0x |
|
|
|
2.0x |
|
|
|
1.9x |
|
|
|
1.3x |
|
Debt to Adjusted EBITDA (2) (3) |
|
|
4.3x |
|
|
|
4.3x |
|
|
|
6.4x |
|
|
|
3.7x |
|
|
|
4.5x |
|
|
|
4.5x |
|
|
|
5.3x |
|
|
|
5.3x |
|
|
|
4.8x |
|
|
|
3.6x |
|
Return on Capital Employed (4) |
|
|
13% |
|
|
|
13% |
|
|
|
12% |
|
|
|
0% |
|
|
|
(2)% |
|
|
|
(2)% |
|
|
|
(6)% |
|
|
|
(6)% |
|
|
|
6% |
|
|
|
8% |
|
Return on Common Equity
(5) |
|
|
19% |
|
|
|
19% |
|
|
|
17% |
|
|
|
(2)% |
|
|
|
(5)% |
|
|
|
(5)% |
|
|
|
(10)% |
|
|
|
(10)% |
|
|
|
7% |
|
|
|
10% |
|
|
|
|
|
|
2017 |
|
2016 |
Income Tax & Exchange Rates |
|
|
YTD |
|
|
|
Q3 |
|
|
|
Q2 |
|
|
|
Q1 |
|
|
|
Year |
|
|
|
Q4 |
|
|
|
Q3 YTD |
|
|
|
Q3 |
|
|
|
Q2 |
|
|
|
Q1 |
|
Effective Tax Rates Using: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Earnings |
|
|
15.5% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
41.2% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Earnings, Excluding Divestitures |
|
|
5.9% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
33.0% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign Exchange Rates (US$ per C$1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average |
|
|
0.766 |
|
|
|
0.798 |
|
|
|
0.744 |
|
|
|
0.756 |
|
|
|
0.755 |
|
|
|
0.750 |
|
|
|
0.757 |
|
|
|
0.766 |
|
|
|
0.776 |
|
|
|
0.728 |
|
Period End |
|
|
0.801 |
|
|
|
0.801 |
|
|
|
0.771 |
|
|
|
0.751 |
|
|
|
0.745 |
|
|
|
0.745 |
|
|
|
0.762 |
|
|
|
0.762 |
|
|
|
0.769 |
|
|
|
0.771 |
|
|
|
|
|
|
2017 |
|
2016 |
Common Share Information |
|
|
YTD |
|
|
|
Q3 |
|
|
|
Q2 |
|
|
|
Q1 |
|
|
|
Year |
|
|
|
Q4 |
|
|
|
Q3 YTD |
|
|
|
Q3 |
|
|
|
Q2 |
|
|
|
Q1 |
|
Common Shares Outstanding (millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Period End |
|
|
1,228.8 |
|
|
|
1,228.8 |
|
|
|
1,228.8 |
|
|
|
833.3 |
|
|
|
833.3 |
|
|
|
833.3 |
|
|
|
833.3 |
|
|
|
833.3 |
|
|
|
833.3 |
|
|
|
833.3 |
|
Average - Basic and Diluted |
|
|
1,059.9 |
|
|
|
1,228.8 |
|
|
|
1,113.3 |
|
|
|
833.3 |
|
|
|
833.3 |
|
|
|
833.3 |
|
|
|
833.3 |
|
|
|
833.3 |
|
|
|
833.3 |
|
|
|
833.3 |
|
Dividends ($ per share) |
|
|
0.15 |
|
|
|
0.05 |
|
|
|
0.05 |
|
|
|
0.05 |
|
|
|
0.20 |
|
|
|
0.05 |
|
|
|
0.15 |
|
|
|
0.05 |
|
|
|
0.05 |
|
|
|
0.05 |
|
Closing Price - TSX (C$ per share) |
|
|
12.51 |
|
|
|
12.51 |
|
|
|
9.56 |
|
|
|
15.05 |
|
|
|
20.30 |
|
|
|
20.30 |
|
|
|
18.83 |
|
|
|
18.83 |
|
|
|
17.87 |
|
|
|
16.90 |
|
-
NYSE (US$ per share) |
|
|
10.02 |
|
|
|
10.02 |
|
|
|
7.37 |
|
|
|
11.30 |
|
|
|
15.13 |
|
|
|
15.13 |
|
|
|
14.37 |
|
|
|
14.37 |
|
|
|
13.82 |
|
|
|
13.00 |
|
Share Volume Traded (millions) |
|
|
2,205.0 |
|
|
|
804.1 |
|
|
|
907.7 |
|
|
|
493.2 |
|
|
|
1,491.7 |
|
|
|
322.6 |
|
|
|
1,169.1 |
|
|
|
313.0 |
|
|
|
373.3 |
|
|
|
482.8 |
|
|
|
|
|
|
|
|
|
|
|
|
Operating Statistics - Before Royalties |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2017 |
|
2016 |
Upstream Production Volumes |
|
|
YTD |
|
|
|
Q3 |
|
|
|
Q2 |
|
|
|
Q1 |
|
|
|
Year |
|
|
|
Q4 |
|
|
|
Q3 YTD |
|
|
|
Q3 |
|
|
|
Q2 |
|
|
|
Q1 |
|
Crude Oil and Natural Gas Liquids (bbls/d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil Sands |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foster Creek |
|
|
114,632 |
|
|
|
154,363 |
|
|
|
107,859 |
|
|
|
80,866 |
|
|
|
70,244 |
|
|
|
81,588 |
|
|
|
66,435 |
|
|
|
73,798 |
|
|
|
64,544 |
|
|
|
60,882 |
|
Christina Lake |
|
|
154,634 |
|
|
|
208,131 |
|
|
|
153,953 |
|
|
|
100,635 |
|
|
|
79,449 |
|
|
|
82,808 |
|
|
|
78,321 |
|
|
|
79,793 |
|
|
|
78,060 |
|
|
|
77,093 |
|
|
|
|
269,266 |
|
|
|
362,494 |
|
|
|
261,812 |
|
|
|
181,501 |
|
|
|
149,693 |
|
|
|
164,396 |
|
|
|
144,756 |
|
|
|
153,591 |
|
|
|
142,604 |
|
|
|
137,975 |
|
Deep Basin |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Light and Medium Oil |
|
|
3,208 |
|
|
|
6,494 |
|
|
|
3,059 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Natural Gas Liquids
(6) |
|
|
13,498 |
|
|
|
26,370 |
|
|
|
13,835 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
|
16,706 |
|
|
|
32,864 |
|
|
|
16,894 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Conventional |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Heavy Oil |
|
|
26,466 |
|
|
|
25,549 |
|
|
|
26,593 |
|
|
|
27,277 |
|
|
|
29,185 |
|
|
|
28,913 |
|
|
|
29,276 |
|
|
|
28,096 |
|
|
|
28,500 |
|
|
|
31,247 |
|
Light and Medium Oil |
|
|
26,430 |
|
|
|
26,947 |
|
|
|
27,233 |
|
|
|
25,089 |
|
|
|
25,915 |
|
|
|
25,065 |
|
|
|
26,200 |
|
|
|
25,311 |
|
|
|
26,177 |
|
|
|
27,121 |
|
Natural Gas Liquids
(6) |
|
|
1,128 |
|
|
|
1,201 |
|
|
|
1,132 |
|
|
|
1,047 |
|
|
|
1,065 |
|
|
|
1,177 |
|
|
|
1,027 |
|
|
|
1,074 |
|
|
|
799 |
|
|
|
1,208 |
|
|
|
|
54,024 |
|
|
|
53,697 |
|
|
|
54,958 |
|
|
|
53,413 |
|
|
|
56,165 |
|
|
|
55,155 |
|
|
|
56,503 |
|
|
|
54,481 |
|
|
|
55,476 |
|
|
|
59,576 |
|
Total Crude Oil and Natural Gas Liquids |
|
|
339,996 |
|
|
|
449,055 |
|
|
|
333,664 |
|
|
|
234,914 |
|
|
|
205,858 |
|
|
|
219,551 |
|
|
|
201,259 |
|
|
|
208,072 |
|
|
|
198,080 |
|
|
|
197,551 |
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas (MMcf/d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil Sands |
|
|
11 |
|
|
|
6 |
|
|
|
12 |
|
|
|
15 |
|
|
|
17 |
|
|
|
17 |
|
|
|
17 |
|
|
|
18 |
|
|
|
18 |
|
|
|
17 |
|
Deep Basin |
|
|
251 |
|
|
|
495 |
|
|
|
253 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Conventional |
|
|
351 |
|
|
|
350 |
|
|
|
355 |
|
|
|
348 |
|
|
|
377 |
|
|
|
362 |
|
|
|
382 |
|
|
|
374 |
|
|
|
381 |
|
|
|
391 |
|
Total Natural Gas |
|
|
613 |
|
|
|
851 |
|
|
|
620 |
|
|
|
363 |
|
|
|
394 |
|
|
|
379 |
|
|
|
399 |
|
|
|
392 |
|
|
|
399 |
|
|
|
408 |
|
Total Production (7) (BOE/d) |
|
|
442,143 |
|
|
|
590,851 |
|
|
|
436,929 |
|
|
|
295,414 |
|
|
|
271,525 |
|
|
|
282,718 |
|
|
|
267,759 |
|
|
|
273,405 |
|
|
|
264,580 |
|
|
|
265,551 |
|
(1) |
Net debt includes the Companys short-term borrowings and the current and long-term portions of long-term debt, net
of cash and cash equivalents. |
(2) |
Debt includes the Companys short-term borrowings and the current and long-term portions of long-term debt.
|
(3) |
Adjusted EBITDA is defined as earnings before finance costs, interest income, income tax expense, depreciation, depletion
and amortization, revaluation gain, remeasurement gains (losses) on contingent consideration, goodwill impairments, asset impairments and reversals, 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. |
(4) |
Return on capital employed is calculated, on a trailing twelve-month basis, as net earnings before after-tax interest divided by average shareholders equity plus average debt. |
(5) |
Return on common equity is calculated, on a trailing twelve-month basis, as net earnings divided by average
shareholders equity. |
(6) |
Natural gas liquids include condensate volumes. |
(7) |
Natural gas volumes have been converted to barrels of oil equivalent (BOE) on the basis of six thousand cubic
feet (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 to 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. |
|
|
|
Cenovus Energy Inc. Third Quarter 2017 Report |
|
Page 84 Supplemental
Information |
SUPPLEMENTAL INFORMATION (unaudited)
Operating Statistics - Before Royalties (continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2017 |
|
|
2016 |
|
Selected Average Benchmark Prices |
|
|
YTD |
|
|
|
Q3 |
|
|
|
Q2 |
|
|
|
Q1 |
|
|
|
Year |
|
|
|
Q4 |
|
|
|
Q3 YTD |
|
|
|
Q3 |
|
|
|
Q2 |
|
|
|
Q1 |
|
Crude Oil Prices (US$/bbl) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Brent |
|
|
52.59 |
|
|
|
52.18 |
|
|
|
50.92 |
|
|
|
54.66 |
|
|
|
45.04 |
|
|
|
51.13 |
|
|
|
43.01 |
|
|
|
46.98 |
|
|
|
46.97 |
|
|
|
35.08 |
|
West Texas Intermediate (WTI) |
|
|
49.47 |
|
|
|
48.21 |
|
|
|
48.29 |
|
|
|
51.91 |
|
|
|
43.32 |
|
|
|
49.29 |
|
|
|
41.33 |
|
|
|
44.94 |
|
|
|
45.59 |
|
|
|
33.45 |
|
Differential Brent - WTI |
|
|
3.12 |
|
|
|
3.97 |
|
|
|
2.63 |
|
|
|
2.75 |
|
|
|
1.72 |
|
|
|
1.84 |
|
|
|
1.68 |
|
|
|
2.04 |
|
|
|
1.38 |
|
|
|
1.63 |
|
Western Canadian Select (WCS) |
|
|
37.59 |
|
|
|
38.27 |
|
|
|
37.16 |
|
|
|
37.33 |
|
|
|
29.48 |
|
|
|
34.97 |
|
|
|
27.65 |
|
|
|
31.44 |
|
|
|
32.29 |
|
|
|
19.21 |
|
WCS (C$) |
|
|
49.07 |
|
|
|
47.96 |
|
|
|
49.95 |
|
|
|
49.38 |
|
|
|
39.05 |
|
|
|
46.63 |
|
|
|
36.35 |
|
|
|
41.04 |
|
|
|
41.61 |
|
|
|
26.39 |
|
Mixed Sweet Blend (US$) |
|
|
46.57 |
|
|
|
45.32 |
|
|
|
46.03 |
|
|
|
48.37 |
|
|
|
40.11 |
|
|
|
46.18 |
|
|
|
38.08 |
|
|
|
41.99 |
|
|
|
42.51 |
|
|
|
29.76 |
|
Differential WTI - WCS |
|
|
11.88 |
|
|
|
9.94 |
|
|
|
11.13 |
|
|
|
14.58 |
|
|
|
13.84 |
|
|
|
14.32 |
|
|
|
13.68 |
|
|
|
13.50 |
|
|
|
13.30 |
|
|
|
14.24 |
|
Condensate (C5 @ Edmonton) |
|
|
49.44 |
|
|
|
47.61 |
|
|
|
48.44 |
|
|
|
52.26 |
|
|
|
42.47 |
|
|
|
48.33 |
|
|
|
40.51 |
|
|
|
43.07 |
|
|
|
44.07 |
|
|
|
34.39 |
|
Differential WTI - Condensate (Premium)/Discount |
|
|
0.03 |
|
|
|
0.60 |
|
|
|
(0.15 |
) |
|
|
(0.35 |
) |
|
|
0.85 |
|
|
|
0.96 |
|
|
|
0.82 |
|
|
|
1.87 |
|
|
|
1.52 |
|
|
|
(0.94 |
) |
|
|
|
|
|
|
|
|
|
|
|
Refining Margins 3-2-1
Crack Spreads (1) (US$/bbl) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Chicago |
|
|
15.33 |
|
|
|
19.66 |
|
|
|
14.78 |
|
|
|
11.54 |
|
|
|
13.07 |
|
|
|
10.96 |
|
|
|
13.77 |
|
|
|
14.58 |
|
|
|
17.15 |
|
|
|
9.58 |
|
Group 3 |
|
|
15.89 |
|
|
|
20.20 |
|
|
|
14.27 |
|
|
|
13.18 |
|
|
|
12.27 |
|
|
|
10.95 |
|
|
|
12.71 |
|
|
|
14.56 |
|
|
|
13.03 |
|
|
|
10.52 |
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Prices |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
AECO (C$/Mcf) |
|
|
2.58 |
|
|
|
2.04 |
|
|
|
2.77 |
|
|
|
2.94 |
|
|
|
2.09 |
|
|
|
2.81 |
|
|
|
1.85 |
|
|
|
2.20 |
|
|
|
1.25 |
|
|
|
2.11 |
|
NYMEX (US$/Mcf) |
|
|
3.17 |
|
|
|
3.00 |
|
|
|
3.18 |
|
|
|
3.32 |
|
|
|
2.46 |
|
|
|
2.98 |
|
|
|
2.29 |
|
|
|
2.81 |
|
|
|
1.95 |
|
|
|
2.09 |
|
Differential NYMEX - AECO (US$/Mcf) |
|
|
1.21 |
|
|
|
1.39 |
|
|
|
1.13 |
|
|
|
1.10 |
|
|
|
0.89 |
|
|
|
0.86 |
|
|
|
0.89 |
|
|
|
1.13 |
|
|
|
0.99 |
|
|
|
0.56 |
|
|
|
|
|
|
2017 |
|
|
2016 |
|
Average Royalty Rates
(Excluding Realized Gain (Loss) on Risk Management) |
|
|
YTD |
|
|
|
Q3 |
|
|
|
Q2 |
|
|
|
Q1 |
|
|
|
Year |
|
|
|
Q4 |
|
|
|
Q3 YTD |
|
|
|
Q3 |
|
|
|
Q2 |
|
|
|
Q1 |
|
Oil Sands |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foster Creek |
|
|
8.4% |
|
|
|
9.1% |
|
|
|
7.3% |
|
|
|
8.5% |
|
|
|
0.0% |
|
|
|
(0.9)% |
|
|
|
0.5% |
|
|
|
0.8% |
|
|
|
1.0% |
|
|
|
(4.9)% |
|
Christina Lake |
|
|
2.1% |
|
|
|
1.6% |
|
|
|
2.6% |
|
|
|
2.7% |
|
|
|
1.6% |
|
|
|
1.8% |
|
|
|
1.4% |
|
|
|
1.6% |
|
|
|
1.2% |
|
|
|
1.2% |
|
|
|
|
|
|
|
|
|
|
|
|
Deep Basin |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil |
|
|
15.2% |
|
|
|
14.5% |
|
|
|
17.4% |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Natural Gas Liquids |
|
|
9.7% |
|
|
|
10.0% |
|
|
|
9.2% |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Natural Gas |
|
|
3.7% |
|
|
|
3.5% |
|
|
|
4.1% |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
Conventional Oil |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pelican Lake |
|
|
18.9% |
|
|
|
19.6% |
|
|
|
17.4% |
|
|
|
19.8% |
|
|
|
12.5% |
|
|
|
11.9% |
|
|
|
12.8% |
|
|
|
14.1% |
|
|
|
14.3% |
|
|
|
8.3% |
|
Weyburn |
|
|
26.3% |
|
|
|
24.8% |
|
|
|
25.8% |
|
|
|
28.3% |
|
|
|
23.6% |
|
|
|
28.3% |
|
|
|
21.6% |
|
|
|
23.0% |
|
|
|
23.9% |
|
|
|
16.6% |
|
Other |
|
|
13.0% |
|
|
|
13.8% |
|
|
|
12.7% |
|
|
|
12.4% |
|
|
|
12.8% |
|
|
|
19.3% |
|
|
|
10.1% |
|
|
|
10.4% |
|
|
|
8.6% |
|
|
|
12.0% |
|
Natural Gas Liquids |
|
|
12.8% |
|
|
|
12.2% |
|
|
|
13.0% |
|
|
|
13.3% |
|
|
|
13.5% |
|
|
|
12.2% |
|
|
|
14.3% |
|
|
|
12.0% |
|
|
|
15.0% |
|
|
|
16.1% |
|
Natural Gas |
|
|
5.1% |
|
|
|
5.1% |
|
|
|
5.2% |
|
|
|
4.8% |
|
|
|
4.6% |
|
|
|
5.3% |
|
|
|
4.2% |
|
|
|
4.5% |
|
|
|
3.7% |
|
|
|
4.3% |
|
|
|
|
|
|
2017 |
|
|
2016 |
|
Oil Sands Netbacks
(2) (Excluding Realized Gain (Loss) on Risk Management) |
|
|
YTD |
|
|
|
Q3 |
|
|
|
Q2 |
|
|
|
Q1 |
|
|
|
Year |
|
|
|
Q4 |
|
|
|
Q3 YTD |
|
|
|
Q3 |
|
|
|
Q2 |
|
|
|
Q1 |
|
Heavy Oil - Foster Creek ($/bbl) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales Price |
|
|
42.22 |
|
|
|
41.57 |
|
|
|
44.38 |
|
|
|
40.62 |
|
|
|
30.32 |
|
|
|
38.59 |
|
|
|
26.97 |
|
|
|
33.61 |
|
|
|
33.40 |
|
|
|
11.82 |
|
Royalties |
|
|
2.80 |
|
|
|
2.98 |
|
|
|
2.49 |
|
|
|
2.83 |
|
|
|
(0.01 |
) |
|
|
(0.27 |
) |
|
|
0.10 |
|
|
|
0.19 |
|
|
|
0.23 |
|
|
|
(0.16 |
) |
Transportation and Blending |
|
|
9.01 |
|
|
|
8.68 |
|
|
|
10.44 |
|
|
|
7.72 |
|
|
|
8.84 |
|
|
|
7.37 |
|
|
|
9.43 |
|
|
|
8.38 |
|
|
|
11.44 |
|
|
|
8.70 |
|
Operating
|
|
|
10.49 |
|
|
|
9.53 |
|
|
|
12.31 |
|
|
|
9.99 |
|
|
|
10.55 |
|
|
|
10.60 |
|
|
|
10.52 |
|
|
|
9.63 |
|
|
|
10.15 |
|
|
|
12.05 |
|
Netback |
|
|
19.92 |
|
|
|
20.38 |
|
|
|
19.14 |
|
|
|
20.08 |
|
|
|
10.94 |
|
|
|
20.89 |
|
|
|
6.92 |
|
|
|
15.41 |
|
|
|
11.58 |
|
|
|
(8.77 |
) |
Heavy Oil - Christina Lake
($/bbl) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales Price |
|
|
37.47 |
|
|
|
38.84 |
|
|
|
36.54 |
|
|
|
35.86 |
|
|
|
25.30 |
|
|
|
34.78 |
|
|
|
22.01 |
|
|
|
29.11 |
|
|
|
28.31 |
|
|
|
8.85 |
|
Royalties |
|
|
0.71 |
|
|
|
0.55 |
|
|
|
0.85 |
|
|
|
0.86 |
|
|
|
0.33 |
|
|
|
0.56 |
|
|
|
0.25 |
|
|
|
0.41 |
|
|
|
0.28 |
|
|
|
0.05 |
|
Transportation and Blending |
|
|
4.12 |
|
|
|
4.14 |
|
|
|
4.10 |
|
|
|
4.13 |
|
|
|
4.68 |
|
|
|
4.08 |
|
|
|
4.89 |
|
|
|
4.49 |
|
|
|
4.90 |
|
|
|
5.28 |
|
Operating
|
|
|
6.80 |
|
|
|
6.08 |
|
|
|
7.04 |
|
|
|
8.08 |
|
|
|
7.48 |
|
|
|
8.15 |
|
|
|
7.24 |
|
|
|
7.72 |
|
|
|
6.35 |
|
|
|
7.61 |
|
Netback |
|
|
25.84 |
|
|
|
28.07 |
|
|
|
24.55 |
|
|
|
22.79 |
|
|
|
12.81 |
|
|
|
21.99 |
|
|
|
9.63 |
|
|
|
16.49 |
|
|
|
16.78 |
|
|
|
(4.09 |
) |
Total Heavy Oil - Oil Sands
($/bbl) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales Price |
|
|
39.52 |
|
|
|
40.02 |
|
|
|
39.73 |
|
|
|
38.08 |
|
|
|
27.64 |
|
|
|
36.67 |
|
|
|
24.28 |
|
|
|
31.30 |
|
|
|
30.59 |
|
|
|
10.13 |
|
Royalties |
|
|
1.61 |
|
|
|
1.60 |
|
|
|
1.52 |
|
|
|
1.78 |
|
|
|
0.17 |
|
|
|
0.14 |
|
|
|
0.18 |
|
|
|
0.30 |
|
|
|
0.26 |
|
|
|
(0.04 |
) |
Transportation and Blending |
|
|
6.23 |
|
|
|
6.11 |
|
|
|
6.68 |
|
|
|
5.81 |
|
|
|
6.62 |
|
|
|
5.71 |
|
|
|
6.96 |
|
|
|
6.39 |
|
|
|
7.84 |
|
|
|
6.75 |
|
Operating
|
|
|
8.40 |
|
|
|
7.58 |
|
|
|
9.19 |
|
|
|
8.97 |
|
|
|
8.91 |
|
|
|
9.37 |
|
|
|
8.74 |
|
|
|
8.65 |
|
|
|
8.06 |
|
|
|
9.52 |
|
Netback |
|
|
23.28 |
|
|
|
24.73 |
|
|
|
22.34 |
|
|
|
21.52 |
|
|
|
11.94 |
|
|
|
21.45 |
|
|
|
8.40 |
|
|
|
15.96 |
|
|
|
14.43 |
|
|
|
(6.10 |
) |
|
|
|
|
|
2017 |
|
|
2016 |
|
Deep Basin Netbacks
(2) (Excluding Realized Gain (Loss) on Risk Management) |
|
|
YTD |
|
|
|
Q3 |
|
|
|
Q2 |
|
|
|
Q1 |
|
|
|
Year |
|
|
|
Q4 |
|
|
|
Q3 YTD |
|
|
|
Q3 |
|
|
|
Q2 |
|
|
|
Q1 |
|
Total Deep Basin (3) ($/BOE)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales Price |
|
|
19.07 |
|
|
|
17.61 |
|
|
|
21.94 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Royalties |
|
|
1.34 |
|
|
|
1.28 |
|
|
|
1.45 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Transportation and Blending |
|
|
1.96 |
|
|
|
1.96 |
|
|
|
1.96 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Operating |
|
|
8.95 |
|
|
|
9.00 |
|
|
|
8.84 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Production and Mineral Taxes |
|
|
0.03 |
|
|
|
0.03 |
|
|
|
0.03 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Netback |
|
|
6.79 |
|
|
|
5.34 |
|
|
|
9.66 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
(1) |
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 on a last in, first out accounting basis (LIFO). |
(2) |
Netback is a non-GAAP measure commonly used in the oil and gas industry to assist in measuring operating performance on a per-unit basis.
Netbacks reflect our margin on a per-barrel basis of unblended crude oil. Netback is defined as gross sales less royalties, transportation and blending, operating expenses and production and mineral taxes
divided by sales volumes. Netbacks do not reflect the non-cash write-downs of product inventory until the product is sold. The crude oil sales price, transportation and blending costs, and sales volumes
exclude the impact of purchased condensate. Condensate is blended with the heavy oil to reduce its thickness in order to transport it to market. Our Netback calculation is aligned with the definition found in the Canadian Oil and Gas Evaluation
Handbook. The reconciliation of the financial components of each Netback to Operating Margin can be found in our quarterly and annual Managements Discussion and Analysis and our Annual Information Form. |
(3) |
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 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 to 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. |
|
|
|
Cenovus Energy Inc. Third Quarter 2017 Report |
|
Page 85 Supplemental
Information |
SUPPLEMENTAL INFORMATION (unaudited)
Operating Statistics - Before Royalties (continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2017 |
|
2016 |
Conventional Netbacks (1) (Excluding Realized Gain (Loss) on Risk Management) |
|
|
YTD |
|
|
|
Q3 |
|
|
|
Q2 |
|
|
|
Q1 |
|
|
|
Year |
|
|
|
Q4 |
|
|
|
Q3 YTD |
|
|
|
Q3 |
|
|
|
Q2 |
|
|
|
Q1 |
|
Heavy Oil - Conventional
($/bbl) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales Price |
|
|
47.46 |
|
|
|
48.01 |
|
|
|
46.67 |
|
|
|
47.77 |
|
|
|
35.82 |
|
|
|
40.72 |
|
|
|
34.18 |
|
|
|
40.50 |
|
|
|
36.77 |
|
|
|
25.99 |
|
Royalties |
|
|
6.72 |
|
|
|
7.04 |
|
|
|
6.15 |
|
|
|
7.03 |
|
|
|
3.31 |
|
|
|
4.08 |
|
|
|
3.06 |
|
|
|
3.97 |
|
|
|
3.95 |
|
|
|
1.40 |
|
Transportation and Blending |
|
|
4.44 |
|
|
|
5.45 |
|
|
|
4.48 |
|
|
|
3.40 |
|
|
|
4.60 |
|
|
|
4.90 |
|
|
|
4.50 |
|
|
|
4.86 |
|
|
|
3.85 |
|
|
|
4.77 |
|
Operating |
|
|
14.30 |
|
|
|
15.50 |
|
|
|
14.56 |
|
|
|
12.86 |
|
|
|
13.38 |
|
|
|
14.69 |
|
|
|
12.94 |
|
|
|
12.43 |
|
|
|
12.34 |
|
|
|
13.98 |
|
Production and Mineral Taxes |
|
|
0.01 |
|
|
|
0.01 |
|
|
|
0.01 |
|
|
|
0.02 |
|
|
|
0.01 |
|
|
|
0.01 |
|
|
|
- |
|
|
|
0.01 |
|
|
|
0.01 |
|
|
|
- |
|
Netback |
|
|
21.99 |
|
|
|
20.01 |
|
|
|
21.47 |
|
|
|
24.46 |
|
|
|
14.52 |
|
|
|
17.04 |
|
|
|
13.68 |
|
|
|
19.23 |
|
|
|
16.62 |
|
|
|
5.84 |
|
Light and Medium Oil ($/bbl) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales Price |
|
|
54.97 |
|
|
|
51.91 |
|
|
|
56.40 |
|
|
|
56.84 |
|
|
|
46.48 |
|
|
|
55.35 |
|
|
|
43.66 |
|
|
|
48.97 |
|
|
|
48.09 |
|
|
|
34.36 |
|
Royalties |
|
|
11.47 |
|
|
|
10.22 |
|
|
|
11.58 |
|
|
|
12.75 |
|
|
|
9.28 |
|
|
|
14.87 |
|
|
|
7.50 |
|
|
|
8.91 |
|
|
|
8.52 |
|
|
|
5.18 |
|
Transportation and Blending |
|
|
2.79 |
|
|
|
2.85 |
|
|
|
2.82 |
|
|
|
2.70 |
|
|
|
2.73 |
|
|
|
2.69 |
|
|
|
2.74 |
|
|
|
2.71 |
|
|
|
2.77 |
|
|
|
2.73 |
|
Operating |
|
|
16.68 |
|
|
|
17.19 |
|
|
|
16.08 |
|
|
|
16.77 |
|
|
|
15.65 |
|
|
|
16.05 |
|
|
|
15.52 |
|
|
|
13.94 |
|
|
|
16.21 |
|
|
|
16.34 |
|
Production and Mineral Taxes |
|
|
1.77 |
|
|
|
1.54 |
|
|
|
1.85 |
|
|
|
1.95 |
|
|
|
1.24 |
|
|
|
1.50 |
|
|
|
1.15 |
|
|
|
1.48 |
|
|
|
1.18 |
|
|
|
0.82 |
|
Netback |
|
|
22.26 |
|
|
|
20.11 |
|
|
|
24.07 |
|
|
|
22.67 |
|
|
|
17.58 |
|
|
|
20.24 |
|
|
|
16.75 |
|
|
|
21.93 |
|
|
|
19.41 |
|
|
|
9.29 |
|
Natural Gas Liquids ($/bbl) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales Price |
|
|
42.24 |
|
|
|
38.12 |
|
|
|
41.06 |
|
|
|
48.35 |
|
|
|
31.16 |
|
|
|
40.79 |
|
|
|
27.45 |
|
|
|
29.71 |
|
|
|
28.11 |
|
|
|
24.99 |
|
Royalties |
|
|
5.42 |
|
|
|
4.66 |
|
|
|
5.32 |
|
|
|
6.42 |
|
|
|
4.21 |
|
|
|
4.97 |
|
|
|
3.92 |
|
|
|
3.58 |
|
|
|
4.20 |
|
|
|
4.03 |
|
Netback |
|
|
36.82 |
|
|
|
33.46 |
|
|
|
35.74 |
|
|
|
41.93 |
|
|
|
26.95 |
|
|
|
35.82 |
|
|
|
23.53 |
|
|
|
26.13 |
|
|
|
23.91 |
|
|
|
20.96 |
|
Natural Gas ($/Mcf) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales Price |
|
|
2.58 |
|
|
|
1.94 |
|
|
|
2.80 |
|
|
|
3.00 |
|
|
|
2.33 |
|
|
|
3.00 |
|
|
|
2.11 |
|
|
|
2.49 |
|
|
|
1.52 |
|
|
|
2.31 |
|
Royalties |
|
|
0.13 |
|
|
|
0.10 |
|
|
|
0.14 |
|
|
|
0.14 |
|
|
|
0.10 |
|
|
|
0.15 |
|
|
|
0.08 |
|
|
|
0.10 |
|
|
|
0.05 |
|
|
|
0.09 |
|
Transportation and Blending |
|
|
0.11 |
|
|
|
0.11 |
|
|
|
0.08 |
|
|
|
0.13 |
|
|
|
0.11 |
|
|
|
0.12 |
|
|
|
0.11 |
|
|
|
0.10 |
|
|
|
0.14 |
|
|
|
0.10 |
|
Operating |
|
|
1.22 |
|
|
|
1.19 |
|
|
|
1.15 |
|
|
|
1.31 |
|
|
|
1.12 |
|
|
|
1.20 |
|
|
|
1.09 |
|
|
|
1.03 |
|
|
|
1.05 |
|
|
|
1.20 |
|
Production and Mineral Taxes |
|
|
0.01 |
|
|
|
0.01 |
|
|
|
0.01 |
|
|
|
0.02 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
0.01 |
|
|
|
- |
|
|
|
- |
|
Netback |
|
|
1.11 |
|
|
|
0.53 |
|
|
|
1.42 |
|
|
|
1.40 |
|
|
|
1.00 |
|
|
|
1.53 |
|
|
|
0.83 |
|
|
|
1.25 |
|
|
|
0.28 |
|
|
|
0.92 |
|
Total Conventional (2) ($/BOE)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales Price |
|
|
32.54 |
|
|
|
29.94 |
|
|
|
33.53 |
|
|
|
34.19 |
|
|
|
26.54 |
|
|
|
31.98 |
|
|
|
24.79 |
|
|
|
28.59 |
|
|
|
24.49 |
|
|
|
21.47 |
|
Royalties |
|
|
4.73 |
|
|
|
4.45 |
|
|
|
4.69 |
|
|
|
5.07 |
|
|
|
3.18 |
|
|
|
4.77 |
|
|
|
2.67 |
|
|
|
3.24 |
|
|
|
3.01 |
|
|
|
1.81 |
|
Transportation and Blending |
|
|
2.03 |
|
|
|
2.26 |
|
|
|
2.00 |
|
|
|
1.82 |
|
|
|
2.08 |
|
|
|
2.17 |
|
|
|
2.05 |
|
|
|
2.09 |
|
|
|
1.96 |
|
|
|
2.09 |
|
Operating |
|
|
11.08 |
|
|
|
11.38 |
|
|
|
10.85 |
|
|
|
10.99 |
|
|
|
10.23 |
|
|
|
10.92 |
|
|
|
10.01 |
|
|
|
9.30 |
|
|
|
9.89 |
|
|
|
10.79 |
|
Production and Mineral Taxes |
|
|
0.47 |
|
|
|
0.42 |
|
|
|
0.47 |
|
|
|
0.51 |
|
|
|
0.27 |
|
|
|
0.31 |
|
|
|
0.26 |
|
|
|
0.35 |
|
|
|
0.27 |
|
|
|
0.16 |
|
Netback |
|
|
14.23 |
|
|
|
11.43 |
|
|
|
15.52 |
|
|
|
15.80 |
|
|
|
10.78 |
|
|
|
13.81 |
|
|
|
9.80 |
|
|
|
13.61 |
|
|
|
9.36 |
|
|
|
6.62 |
|
|
|
|
|
|
2017 |
|
2016 |
Consolidated Netbacks (1) (Excluding Realized Gain (Loss) on Risk Management) |
|
|
YTD |
|
|
|
Q3 |
|
|
|
Q2 |
|
|
|
Q1 |
|
|
|
Year |
|
|
|
Q4 |
|
|
|
Q3 YTD |
|
|
|
Q3 |
|
|
|
Q2 |
|
|
|
Q1 |
|
Total Consolidated (2) ($/BOE)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales Price |
|
|
34.89 |
|
|
|
33.71 |
|
|
|
35.58 |
|
|
|
36.37 |
|
|
|
27.01 |
|
|
|
34.53 |
|
|
|
24.37 |
|
|
|
29.98 |
|
|
|
27.56 |
|
|
|
15.43 |
|
Royalties |
|
|
2.37 |
|
|
|
2.08 |
|
|
|
2.34 |
|
|
|
3.06 |
|
|
|
1.49 |
|
|
|
2.06 |
|
|
|
1.29 |
|
|
|
1.55 |
|
|
|
1.51 |
|
|
|
0.82 |
|
Transportation and Blending |
|
|
4.56 |
|
|
|
4.56 |
|
|
|
4.78 |
|
|
|
4.20 |
|
|
|
4.56 |
|
|
|
4.20 |
|
|
|
4.69 |
|
|
|
4.51 |
|
|
|
5.07 |
|
|
|
4.51 |
|
Operating |
|
|
9.18 |
|
|
|
8.59 |
|
|
|
9.59 |
|
|
|
9.80 |
|
|
|
9.51 |
|
|
|
10.05 |
|
|
|
9.32 |
|
|
|
8.92 |
|
|
|
8.89 |
|
|
|
10.14 |
|
Production and Mineral Taxes |
|
|
0.12 |
|
|
|
0.08 |
|
|
|
0.13 |
|
|
|
0.20 |
|
|
|
0.12 |
|
|
|
0.13 |
|
|
|
0.12 |
|
|
|
0.15 |
|
|
|
0.12 |
|
|
|
0.08 |
|
Netback |
|
|
18.66 |
|
|
|
18.40 |
|
|
|
18.74 |
|
|
|
19.11 |
|
|
|
11.33 |
|
|
|
18.09 |
|
|
|
8.95 |
|
|
|
14.85 |
|
|
|
11.97 |
|
|
|
(0.12 |
) |
|
|
|
|
|
2017 |
|
2016 |
Realized Gain (Loss) on Risk Management |
|
|
YTD |
|
|
|
Q3 |
|
|
|
Q2 |
|
|
|
Q1 |
|
|
|
Year |
|
|
|
Q4 |
|
|
|
Q3 YTD |
|
|
|
Q3 |
|
|
|
Q2 |
|
|
|
Q1 |
|
Total Crude Oil ($/bbl) |
|
|
(1.06 |
) |
|
|
(0.37 |
) |
|
|
0.39 |
|
|
|
(4.55 |
) |
|
|
3.24 |
|
|
|
0.91 |
|
|
|
4.08 |
|
|
|
2.15 |
|
|
|
1.97 |
|
|
|
8.21 |
|
Total Production
(2) ($/BOE) |
|
|
(0.77 |
) |
|
|
(0.24 |
) |
|
|
0.28 |
|
|
|
(3.56 |
) |
|
|
2.44 |
|
|
|
0.70 |
|
|
|
3.05 |
|
|
|
1.63 |
|
|
|
1.46 |
|
|
|
6.08 |
|
|
|
|
|
|
2017 |
|
2016 |
Refinery Operations (3) |
|
|
YTD |
|
|
|
Q3 |
|
|
|
Q2 |
|
|
|
Q1 |
|
|
|
Year |
|
|
|
Q4 |
|
|
|
Q3 YTD |
|
|
|
Q3 |
|
|
|
Q2 |
|
|
|
Q1 |
|
Crude Oil Capacity (Mbbls/d) |
|
|
460 |
|
|
|
460 |
|
|
|
460 |
|
|
|
460 |
|
|
|
460 |
|
|
|
460 |
|
|
|
460 |
|
|
|
460 |
|
|
|
460 |
|
|
|
460 |
|
Crude Oil Runs (Mbbls/d) |
|
|
439 |
|
|
|
462 |
|
|
|
449 |
|
|
|
406 |
|
|
|
444 |
|
|
|
421 |
|
|
|
452 |
|
|
|
463 |
|
|
|
458 |
|
|
|
435 |
|
Heavy Oil |
|
|
205 |
|
|
|
213 |
|
|
|
201 |
|
|
|
200 |
|
|
|
233 |
|
|
|
223 |
|
|
|
237 |
|
|
|
241 |
|
|
|
228 |
|
|
|
241 |
|
Light/Medium |
|
|
234 |
|
|
|
249 |
|
|
|
248 |
|
|
|
206 |
|
|
|
211 |
|
|
|
198 |
|
|
|
215 |
|
|
|
222 |
|
|
|
230 |
|
|
|
194 |
|
Crude Utilization |
|
|
95% |
|
|
|
100% |
|
|
|
98% |
|
|
|
88% |
|
|
|
97% |
|
|
|
92% |
|
|
|
98% |
|
|
|
101% |
|
|
|
100% |
|
|
|
95% |
|
Refined Products (Mbbls/d) |
|
|
467 |
|
|
|
490 |
|
|
|
476 |
|
|
|
433 |
|
|
|
471 |
|
|
|
448 |
|
|
|
479 |
|
|
|
494 |
|
|
|
483 |
|
|
|
460 |
|
(1) |
Netback is a non-GAAP measure commonly used in the oil and gas industry to assist
in measuring operating performance on a per-unit basis. Netbacks reflect our margin on a per-barrel basis of unblended crude oil. Netback is defined as gross sales less
royalties, transportation and blending, operating expenses and production and mineral taxes divided by sales volumes. Netbacks do not reflect the non-cash write-downs of product inventory until the product is
sold. The crude oil sales price, transportation and blending costs, and sales volumes exclude the impact of purchased condensate. Condensate is blended with the heavy oil to reduce its thickness in order to transport it to market. Our Netback
calculation is aligned with the definition found in the Canadian Oil and Gas Evaluation Handbook. The reconciliation of the financial components of each Netback to Operating Margin can be found in our quarterly and annual Managements
Discussion and Analysis and our Annual Information Form. |
(2) |
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 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 to 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. |
(3) |
Represents 100% of the Wood River and Borger refinery operations. |
|
|
|
Cenovus Energy Inc. Third Quarter 2017 Report |
|
Page 86 Supplemental
Information |
ADVISORY
FINANCIAL
INFORMATION
Basis of Presentation
Cenovus reports
financial results in Canadian dollars and presents production volumes on a net to Cenovus before royalties basis, unless otherwise stated. Cenovus prepares its financial statements in accordance with International Financial Reporting Standards
(IFRS).
OIL AND GAS INFORMATION
The estimates of
reserves were prepared effective December 31, 2016 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, 2017 price forecast. For additional information about
our reserves and other oil and gas information, see Reserves Data and Other Oil and Gas Information in our AIF for the year ended December 31, 2016 and our Statement of Contingent and Prospective Resources.
Barrels of Oil Equivalent Natural gas volumes have been converted to barrels of oil equivalent (BOE) on the basis of six thousand cubic feet (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.
NON-GAAP MEASURES AND ADDITIONAL SUBTOTAL
The following measures do not have a standardized meaning as prescribed by IFRS and therefore are considered
non-GAAP measures. Readers should not consider these measures in isolation or as a substitute for analysis of Cenovuss results as reported under IFRS. These measures are defined differently by different
companies in the oil and gas industry and may not be comparable to similar measures presented by other issuers.
Adjusted Funds Flow is used in the
oil and gas industry to assist in measuring a companys ability to finance its capital programs and meet its financial obligations. Adjusted Funds Flow is defined as Cash from Operating Activities excluding net change in other assets and
liabilities and net change in non-cash working capital. Net change in other assets and liabilities is composed of site restoration costs and pension funding. Non-cash
working capital is composed of current assets and current liabilities, excluding cash and cash equivalents, risk management, the contingent payment, assets held for sale and liabilities related to assets held for sale.
Free Funds Flow is defined as Adjusted Funds Flow less capital investment.
Operating earnings (Loss) is a non-GAAP measure used to provide a consistent measure of the comparability of
Cenovuss 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, revaluation gain, 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.
Debt is defined as short-term borrowings and long-term debt, including the current portion. Net debt is defined as
debt net of cash and cash equivalents.
Operating Margin is an additional subtotal found in Note 1 and Note 8 of the Consolidated Financial
Statements and is used to provide a consistent measure of the cash generating performance of Cenovuss assets for comparability of its underlying financial performance between periods. Operating Margin is defined as revenues less purchased
product, transportation and blending, operating expenses, production and mineral taxes plus realized gains less realized losses on risk management activities. Items within the Corporate and Eliminations segment are excluded from the calculation of
Operating Margin.
|
|
|
Cenovus Energy Inc. Third Quarter
2017 Report |
|
Page 87
Advisory |
FORWARD-LOOKING INFORMATION
This quarterly report contains certain forward-looking statements and forward-looking information (collectively referred to as forward-looking
information) within the meaning of applicable securities legislation, including the United States Private Securities Litigation Reform Act of 1995, about Cenovuss current expectations, estimates and projections about the future, based on
certain assumptions made by the Company in light of its experience and perception of historical trends. Although Cenovus believes that the expectations represented by such forward-looking information are reasonable, there can be no assurance that
such expectations will prove to be correct.
Forward-looking information in this document is identified by words such as anticipate,
committed, can be, could, estimate, expect, focus, forecast, forward, may, on track outlook, plan,
position, potential, priority, project, should, strategy, target, will or similar expressions and includes suggestions of future outcomes, including
statements about: strategy and related milestones and schedules, including expected oil sands expansion phases; projections for the remainder of 2017 and 2018 and the companys related plans and strategies; development plans; forecast operating
and financial results; priorities for 2018 capital investment decisions; planned capital expenditures, including the amount and timing thereof; expected future production; forecast cost savings and sustainability thereof; planned and potential asset
sales and related targets, including expected timelines, targeted proceeds and anticipated use of proceeds; and hedging strategy, including expected impacts thereof. Readers are cautioned not to place undue reliance on forward-looking information as
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: forecast
oil and natural gas prices and other assumptions inherent in Cenovuss 2017 guidance, available at cenovus.com under Investors; projected capital investment
levels, the flexibility of Cenovuss capital spending plans and the associated source of funding; the achievement of further cost reductions and sustainability thereof; expected condensate prices; estimates of quantities of oil, bitumen,
natural gas and liquids from properties and other sources not currently classified as proved; future use and development of technology; Cenovuss ability to obtain necessary regulatory and partner approvals; the successful and timely
implementation of capital projects or stages thereof; Cenovuss ability to generate sufficient cash flow to meet its current and future obligations; estimated abandonment and reclamation costs, including associated levies and regulations;
achievement of expected impacts of the acquisition; successful integration of the Deep Basin Assets; Cenovuss ability to obtain and retain qualified staff and equipment in a timely and cost-efficient manner; Cenovuss ability to access
sufficient capital to pursue its development plans; Cenovuss ability to complete planned and potential asset sales, including with desired transaction metrics and within the timelines it expects; forecast crude oil and natural gas prices,
forecast inflation and other assumptions inherent in current guidance set out below; expected impacts of the contingent payment to ConocoPhillips, including alignment of realized Western Canadian Select (WCS) prices and WCS prices used
to calculate the contingent payment; Cenovuss projected capital investment levels, the flexibility of capital spending plans and the associated sources of funding; sustainability of achieved cost reductions, achievement of further cost
reductions and sustainability thereof; Cenovuss ability to access and implement all technology necessary to achieve expected future results; Cenovuss ability to implement capital projects or stages thereof in a successful and timely
manner; and other risks and uncertainties described from time to time in the filings we make with securities regulatory authorities.
2017
guidance, as updated November 1, 2017, assumes: Brent prices of US$53.50/bbl, WTI prices of US$50.00/bbl; WCS of US$38.25/bbl; NYMEX natural gas prices of US$3.15/MMBtu; AECO natural gas prices of $2.40/GJ; Chicago 3-2-1 crack spread of US$15.50/bbl; and an exchange rate of $0.78 US$/C$.
Unless otherwise specifically stated or the context dictates otherwise, the financial outlook and forward-looking metrics in this quarterly report, in
addition to the generally applicable assumptions described above, do not include or account for the effects or impacts of planned asset sales.
The
risk factors and uncertainties that could cause actual results to differ materially, include: possible failure by Cenovus to realize the anticipated benefits of and synergies from the acquisition; possible failure to access or implement some or all
of the technology necessary to efficiently and effectively operate Cenovuss assets and achieve expected future results; volatility of and other assumptions regarding commodity prices; the effectiveness of Cenovuss risk management
program, including the impact of derivative financial instruments, the success of hedging strategies and the sufficiency of Cenovuss liquidity position; the accuracy of cost estimates; commodity
|
|
|
Cenovus Energy Inc. Third Quarter
2017 Report |
|
Page 88
Advisory |
prices, currency and interest rates; possible lack of alignment of realized WCS prices and WCS prices used to calculate the contingent payment to ConocoPhillips; product supply and demand; market
competition, including from alternative energy sources; risks inherent in marketing operations, including credit risks; exposure to counterparties and partners, including ability and willingness of such parties to satisfy contractual obligations in
a timely manner; risks inherent in the operation of Cenovuss crude-by-rail terminal, including health, safety and environmental risks; maintaining desirable ratios
of Debt (and Net Debt) to Adjusted EBITDA as well as Debt (and Net Debt) to Capitalization; Cenovuss ability to access various sources of debt and equity capital, generally, and on terms acceptable to Cenovus; ability to finance growth and
sustaining capital expenditures; changes in credit ratings applicable to Cenovus or any of its securities; changes to Cenovuss dividend plans or strategy, including the dividend reinvestment plan; accuracy of reserves, resources, future
production and future net revenue estimates; Cenovuss ability to replace and expand oil and gas reserves; Cenovuss ability to maintain its relationship with its partners and to successfully manage and operate its integrated business;
reliability of Cenovuss assets including in order to meet production targets; potential disruption or unexpected technical difficulties in developing new products and manufacturing processes; the occurrence of unexpected events such as fires,
severe weather conditions, explosions, blow-outs, equipment failures, transportation incidents and other accidents or similar events; refining and marketing margins; inflationary pressures on operating costs, including labour, natural gas and other
energy sources used in oil sands processes; potential failure of products to achieve or maintain acceptance in the market; risks associated with fossil fuel industry reputation; unexpected cost increases or technical difficulties in constructing or
modifying manufacturing or refining facilities; unexpected difficulties in producing, transporting or refining of crude oil into petroleum and chemical products; risks associated with technology and its application to Cenovuss business; risks
associated with climate change; the timing and the costs of well and pipeline construction; Cenovuss ability to secure adequate and cost-effective product transportation including sufficient pipeline, crude-by-rail, marine or alternate transportation, including to address any gaps caused by constraints in the pipeline system; availability of, and Cenovuss ability to attract and retain, critical
talent; possible failure to obtain and retain qualified staff and equipment in a timely and cost-efficient manner; changes in labour relationships; changes in the regulatory framework in any of the locations in which Cenovus operates, including
changes to the regulatory approval process and land-use designations, royalty, tax, environmental, greenhouse gas, carbon, climate change and other laws or regulations, or changes to the interpretation of such
laws and regulations, as adopted or proposed, the impact thereof and the costs associated with compliance; the expected impact and timing of various accounting pronouncements, rule changes and standards on Cenovuss business, financial results
and consolidated financial statements; changes in general economic, market and business conditions; the political and economic conditions in the countries in which Cenovus operates or supplies; the occurrence of unexpected events such as war,
terrorist threats and the instability resulting therefrom; and risks associated with existing and potential future lawsuits and regulatory actions against Cenovus.
Readers are cautioned that the foregoing lists are not exhaustive and are made as at the date hereof. Events or circumstances could cause actual results
to differ materially from those estimated or projected and expressed in, or implied by, the forward looking information. For a full discussion of material risk factors, see Risk Factors in Cenovuss Annual Information Form (AIF) or
Form 40-F for the period ended December 31, 2016, available on SEDAR at sedar.com, on EDGAR at sec.gov and on Cenovuss website at cenovus.com, and the updates
under Risk Management in Cenovuss most recently filed Managements Discussion and Analysis (MD&A).
ABBREVIATIONS
The following is a summary of the abbreviations that 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 |
BOE |
|
barrel of oil equivalent |
|
MMBtu |
|
million British thermal units |
BOE/d |
|
barrel of oil equivalent per day |
|
GJ |
|
gigajoule |
MMBOE |
|
million barrel of oil equivalent |
|
AECO |
|
Alberta Energy Company |
WTI |
|
West Texas Intermediate |
|
NYMEX |
|
New York Mercantile Exchange |
WCS |
|
Western Canadian Select |
|
|
|
|
CDB |
|
Christina Dilbit Blend |
|
TM |
|
Trademark of Cenovus Energy Inc. |
|
|
|
Cenovus Energy Inc. Third Quarter
2017 Report |
|
Page 89
Advisory |
NETBACK RECONCILIATIONS
The following tables provide a reconciliation of the items comprising Netbacks to Operating Margin found in our Interim Consolidated Financial Statements.
Total Production
Upstream Financial
Results
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Per Interim Consolidated Financial Statements
|
|
|
|
|
Three Months Ended September 30, 2017 ($ millions) |
|
Oil Sands (1) |
|
|
|
Deep Basin (1) |
|
|
|
Conventional (2) |
|
|
|
Total Upstream |
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross Sales |
|
2,210 |
|
|
|
200 |
|
|
|
331 |
|
|
|
2,741 |
Less: Royalties |
|
54 |
|
|
|
13 |
|
|
|
45 |
|
|
|
112 |
|
|
2,156 |
|
|
|
187 |
|
|
|
286 |
|
|
|
2,629 |
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transportation and Blending |
|
1,066 |
|
|
|
22 |
|
|
|
44 |
|
|
|
1,132 |
Operating |
|
257 |
|
|
|
101 |
|
|
|
118 |
|
|
|
476 |
Production and Mineral Taxes |
|
- |
|
|
|
- |
|
|
|
4 |
|
|
|
4 |
Netback |
|
833 |
|
|
|
64 |
|
|
|
120 |
|
|
|
1,017 |
(Gain) Loss on Risk Management |
|
9 |
|
|
|
- |
|
|
|
3 |
|
|
|
12 |
Operating Margin |
|
824 |
|
|
|
64 |
|
|
|
117 |
|
|
|
1,005 |
|
|
|
|
|
|
Per Interim Consolidated Financial Statements |
|
|
|
|
Three Months Ended September 30, 2016 ($ millions) |
|
Oil Sands (1) |
|
|
|
Deep Basin (1) |
|
|
|
Conventional (2) |
|
|
|
Total Upstream |
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross Sales |
|
793 |
|
|
|
- |
|
|
|
330 |
|
|
|
1,123 |
Less: Royalties |
|
4 |
|
|
|
- |
|
|
|
35 |
|
|
|
39 |
|
|
789 |
|
|
|
- |
|
|
|
295 |
|
|
|
1,084 |
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transportation and Blending |
|
429 |
|
|
|
- |
|
|
|
44 |
|
|
|
473 |
Operating |
|
128 |
|
|
|
- |
|
|
|
102 |
|
|
|
230 |
Production and Mineral Taxes |
|
- |
|
|
|
- |
|
|
|
4 |
|
|
|
4 |
Netback |
|
232 |
|
|
|
- |
|
|
|
145 |
|
|
|
377 |
(Gain) Loss on Risk Management |
|
(35) |
|
|
|
- |
|
|
|
(7) |
|
|
|
(42) |
Operating Margin |
|
267 |
|
|
|
- |
|
|
|
152 |
|
|
|
419 |
(1) |
Found in Note 1 of the interim Consolidated Financial Statements. |
(2) |
Found in Note 8 of the interim Consolidated Financial Statements. |
Netback Reconciliations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basis of Netback Calculation |
|
|
|
Adjustments |
|
|
|
Per Above Table |
Three Months Ended September 30, 2017 ($ millions) |
|
Total |
|
|
|
Condensate |
|
|
|
Inventory |
|
|
|
Other |
|
|
|
Total Upstream |
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross Sales |
|
1,836 |
|
|
|
885 |
|
|
|
- |
|
|
|
20 |
|
|
|
2,741 |
Less: Royalties |
|
114 |
|
|
|
- |
|
|
|
- |
|
|
|
(2) |
|
|
|
112 |
|
|
1,722 |
|
|
|
885 |
|
|
|
- |
|
|
|
22 |
|
|
|
2,629 |
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transportation and Blending |
|
248 |
|
|
|
885 |
|
|
|
(1) |
|
|
|
- |
|
|
|
1,132 |
Operating |
|
469 |
|
|
|
- |
|
|
|
- |
|
|
|
7 |
|
|
|
476 |
Production and Mineral Taxes |
|
4 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
4 |
Netback |
|
1,001 |
|
|
|
- |
|
|
|
1 |
|
|
|
15 |
|
|
|
1,017 |
(Gain) Loss on Risk Management |
|
12 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
12 |
Operating Margin |
|
989 |
|
|
|
- |
|
|
|
1 |
|
|
|
15 |
|
|
|
1,005 |
|
|
|
|
|
|
|
|
Basis of Netback Calculation |
|
|
|
Adjustments |
|
|
|
Per Above Table |
Three Months Ended September 30, 2016 ($ millions) |
|
Total |
|
|
|
Condensate |
|
|
|
Inventory |
|
|
|
Other |
|
|
|
Total Upstream |
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross Sales |
|
762 |
|
|
|
358 |
|
|
|
- |
|
|
|
3 |
|
|
|
1,123 |
Less: Royalties |
|
39 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
39 |
|
|
723 |
|
|
|
358 |
|
|
|
- |
|
|
|
3 |
|
|
|
1,084 |
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transportation and Blending |
|
115 |
|
|
|
358 |
|
|
|
- |
|
|
|
- |
|
|
|
473 |
Operating |
|
227 |
|
|
|
- |
|
|
|
- |
|
|
|
3 |
|
|
|
230 |
Production and Mineral Taxes |
|
4 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
4 |
Netback |
|
377 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
377 |
(Gain) Loss on Risk Management |
|
(41) |
|
|
|
- |
|
|
|
- |
|
|
|
(1) |
|
|
|
(42) |
Operating Margin |
|
418 |
|
|
|
- |
|
|
|
- |
|
|
|
1 |
|
|
|
419 |
|
|
|
Cenovus Energy Inc.
Third Quarter 2017 Report |
|
Page 90
Netback Reconciliations |
Total Production
Upstream
Financial Results
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Per Interim Consolidated Financial Statements |
|
|
|
|
Nine Months Ended September 30, 2017 ($ millions) |
|
Oil Sands (1) |
|
|
|
Deep Basin (1) |
|
|
|
Conventional (2) |
|
|
|
Total Upstream |
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross Sales |
|
4,938 |
|
|
|
324 |
|
|
|
1,091 |
|
|
|
6,353 |
Less: Royalties |
|
117 |
|
|
|
21 |
|
|
|
145 |
|
|
|
283 |
|
|
4,821 |
|
|
|
303 |
|
|
|
946 |
|
|
|
6,070 |
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transportation and Blending |
|
2,511 |
|
|
|
32 |
|
|
|
149 |
|
|
|
2,692 |
Operating |
|
618 |
|
|
|
152 |
|
|
|
343 |
|
|
|
1,113 |
Production and Mineral Taxes |
|
- |
|
|
|
- |
|
|
|
14 |
|
|
|
14 |
Netback |
|
1,692 |
|
|
|
119 |
|
|
|
440 |
|
|
|
2,251 |
(Gain) Loss on Risk Management |
|
72 |
|
|
|
- |
|
|
|
19 |
|
|
|
91 |
Operating Margin |
|
1,620 |
|
|
|
119 |
|
|
|
421 |
|
|
|
2,160 |
|
|
|
|
|
|
Per Interim Consolidated Financial Statements |
|
|
|
|
Nine Months Ended September 30, 2016 ($ millions) |
|
Oil Sands (1) |
|
|
|
Deep Basin (1) |
|
|
|
Conventional (2) |
|
|
|
Total Upstream |
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross Sales |
|
1,972 |
|
|
|
- |
|
|
|
898 |
|
|
|
2,870 |
Less: Royalties |
|
7 |
|
|
|
- |
|
|
|
88 |
|
|
|
95 |
|
|
1,965 |
|
|
|
- |
|
|
|
810 |
|
|
|
2,775 |
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transportation and Blending |
|
1,228 |
|
|
|
- |
|
|
|
136 |
|
|
|
1,364 |
Operating |
|
359 |
|
|
|
- |
|
|
|
331 |
|
|
|
690 |
Production and Mineral Taxes |
|
- |
|
|
|
- |
|
|
|
9 |
|
|
|
9 |
Netback |
|
378 |
|
|
|
- |
|
|
|
334 |
|
|
|
712 |
(Gain) Loss on Risk Management |
|
(165) |
|
|
|
- |
|
|
|
(57) |
|
|
|
(222) |
Operating Margin |
|
543 |
|
|
|
- |
|
|
|
391 |
|
|
|
934 |
(1) |
Found in Note 1 of the interim Consolidated Financial Statements. |
(2) |
Found in Note 8 of the interim Consolidated Financial Statements. |
Netback Reconciliations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basis of Netback Calculation |
|
|
|
Adjustments |
|
|
|
Per Above Table |
Nine Months Ended September 30, 2017 ($ millions) |
|
Total |
|
|
|
Condensate |
|
|
|
Inventory |
|
|
|
Other |
|
|
|
Total Upstream |
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross Sales |
|
4,172 |
|
|
|
2,147 |
|
|
|
- |
|
|
|
34 |
|
|
|
6,353 |
Less: Royalties |
|
284 |
|
|
|
- |
|
|
|
- |
|
|
|
(1) |
|
|
|
283 |
|
|
3,888 |
|
|
|
2,147 |
|
|
|
- |
|
|
|
35 |
|
|
|
6,070 |
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transportation and Blending |
|
543 |
|
|
|
2,147 |
|
|
|
- |
|
|
|
2 |
|
|
|
2,692 |
Operating |
|
1,098 |
|
|
|
- |
|
|
|
- |
|
|
|
15 |
|
|
|
1,113 |
Production and Mineral Taxes |
|
14 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
14 |
Netback |
|
2,233 |
|
|
|
- |
|
|
|
- |
|
|
|
18 |
|
|
|
2,251 |
(Gain) Loss on Risk Management |
|
91 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
91 |
Operating Margin |
|
2,142 |
|
|
|
- |
|
|
|
- |
|
|
|
18 |
|
|
|
2,160 |
|
|
|
|
|
|
|
|
Basis of Netback Calculation |
|
|
|
Adjustments |
|
|
|
Per Above Table |
Nine Months Ended September 30, 2016 ($ millions) |
|
Total |
|
|
|
Condensate |
|
|
|
Inventory |
|
|
|
Other |
|
|
|
Total Upstream |
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross Sales |
|
1,790 |
|
|
|
1,070 |
|
|
|
- |
|
|
|
10 |
|
|
|
2,870 |
Less: Royalties |
|
95 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
95 |
|
|
1,695 |
|
|
|
1,070 |
|
|
|
- |
|
|
|
10 |
|
|
|
2,775 |
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transportation and Blending |
|
345 |
|
|
|
1,070 |
|
|
|
(51) |
|
|
|
- |
|
|
|
1,364 |
Operating |
|
684 |
|
|
|
- |
|
|
|
- |
|
|
|
6 |
|
|
|
690 |
Production and Mineral Taxes |
|
9 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
9 |
Netback |
|
657 |
|
|
|
- |
|
|
|
51 |
|
|
|
4 |
|
|
|
712 |
(Gain) Loss on Risk Management |
|
(223) |
|
|
|
- |
|
|
|
- |
|
|
|
1 |
|
|
|
(222) |
Operating Margin |
|
880 |
|
|
|
- |
|
|
|
51 |
|
|
|
3 |
|
|
|
934 |
|
|
|
Cenovus Energy Inc.
Third Quarter 2017 Report |
|
Page 91
Netback Reconciliations |
Oil Sands
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basis of Netback Calculation |
|
|
|
|
|
|
|
Adjustments |
|
|
|
|
|
|
|
Per Interim
Consolidated
Financial
Statements (1) |
Three Months Ended September 30, 2017
($ millions) |
|
Foster
Creek |
|
|
|
Christina
Lake |
|
|
|
Total
Crude Oil |
|
|
|
Natural Gas |
|
|
|
Condensate |
|
|
|
Inventory |
|
|
|
Other |
|
|
|
Total Oil
Sands |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross Sales |
|
603 |
|
|
|
737 |
|
|
|
1,340 |
|
|
|
1 |
|
|
|
863 |
|
|
|
- |
|
|
|
6 |
|
|
|
2,210 |
Less: Royalties |
|
43 |
|
|
|
11 |
|
|
|
54 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
54 |
|
|
560 |
|
|
|
726 |
|
|
|
1,286 |
|
|
|
1 |
|
|
|
863 |
|
|
|
- |
|
|
|
6 |
|
|
|
2,156 |
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transportation and Blending |
|
126 |
|
|
|
79 |
|
|
|
205 |
|
|
|
- |
|
|
|
863 |
|
|
|
(1) |
|
|
|
(1) |
|
|
|
1,066 |
Operating |
|
138 |
|
|
|
116 |
|
|
|
254 |
|
|
|
1 |
|
|
|
- |
|
|
|
- |
|
|
|
2 |
|
|
|
257 |
Netback |
|
296 |
|
|
|
531 |
|
|
|
827 |
|
|
|
- |
|
|
|
- |
|
|
|
1 |
|
|
|
5 |
|
|
|
833 |
(Gain) Loss on Risk Management |
|
2 |
|
|
|
7 |
|
|
|
9 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
9 |
Operating Margin |
|
294 |
|
|
|
524 |
|
|
|
818 |
|
|
|
- |
|
|
|
- |
|
|
|
1 |
|
|
|
5 |
|
|
|
824 |
|
|
|
|
|
|
|
|
|
|
|
|
Basis of Netback Calculation |
|
|
|
|
|
|
|
Adjustments |
|
|
|
|
|
|
|
Per Interim
Consolidated Financial Statements
(1) |
Three Months Ended September 30, 2016
($ millions) |
|
Foster
Creek |
|
|
|
Christina
Lake |
|
|
|
Total
Crude Oil |
|
|
|
Natural Gas |
|
|
|
Condensate |
|
|
|
Inventory |
|
|
|
Other |
|
|
|
Total Oil
Sands |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross Sales |
|
236 |
|
|
|
215 |
|
|
|
451 |
|
|
|
4 |
|
|
|
337 |
|
|
|
- |
|
|
|
1 |
|
|
|
793 |
Less: Royalties |
|
1 |
|
|
|
3 |
|
|
|
4 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
4 |
|
|
235 |
|
|
|
212 |
|
|
|
447 |
|
|
|
4 |
|
|
|
337 |
|
|
|
- |
|
|
|
1 |
|
|
|
789 |
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transportation and Blending |
|
59 |
|
|
|
33 |
|
|
|
92 |
|
|
|
- |
|
|
|
337 |
|
|
|
- |
|
|
|
- |
|
|
|
429 |
Operating |
|
68 |
|
|
|
57 |
|
|
|
125 |
|
|
|
2 |
|
|
|
- |
|
|
|
- |
|
|
|
1 |
|
|
|
128 |
Netback |
|
108 |
|
|
|
122 |
|
|
|
230 |
|
|
|
2 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
232 |
(Gain) Loss on Risk Management |
|
(16) |
|
|
|
(18) |
|
|
|
(34) |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(1) |
|
|
|
(35) |
Operating Margin |
|
124 |
|
|
|
140 |
|
|
|
264 |
|
|
|
2 |
|
|
|
- |
|
|
|
- |
|
|
|
1 |
|
|
|
267 |
|
|
|
|
|
|
|
|
|
|
|
|
Basis of Netback Calculation |
|
|
|
|
|
|
|
Adjustments |
|
|
|
|
|
|
|
Per Interim
Consolidated
Financial Statements (1) |
Nine Months Ended September 30, 2017
($ millions) |
|
Foster
Creek |
|
|
|
Christina
Lake |
|
|
|
Total
Crude Oil |
|
|
|
Natural Gas |
|
|
|
Condensate |
|
|
|
Inventory |
|
|
|
Other |
|
|
|
Total Oil
Sands |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross Sales |
|
1,319 |
|
|
|
1,541 |
|
|
|
2,860 |
|
|
|
7 |
|
|
|
2,060 |
|
|
|
- |
|
|
|
11 |
|
|
|
4,938 |
Less: Royalties |
|
87 |
|
|
|
30 |
|
|
|
117 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
117 |
|
|
1,232 |
|
|
|
1,511 |
|
|
|
2,743 |
|
|
|
7 |
|
|
|
2,060 |
|
|
|
- |
|
|
|
11 |
|
|
|
4,821 |
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transportation and Blending |
|
281 |
|
|
|
170 |
|
|
|
451 |
|
|
|
- |
|
|
|
2,060 |
|
|
|
- |
|
|
|
- |
|
|
|
2,511 |
Operating |
|
328 |
|
|
|
280 |
|
|
|
608 |
|
|
|
6 |
|
|
|
- |
|
|
|
- |
|
|
|
4 |
|
|
|
618 |
Netback |
|
623 |
|
|
|
1,061 |
|
|
|
1,684 |
|
|
|
1 |
|
|
|
- |
|
|
|
- |
|
|
|
7 |
|
|
|
1,692 |
(Gain) Loss on Risk Management |
|
33 |
|
|
|
39 |
|
|
|
72 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
72 |
Operating Margin |
|
590 |
|
|
|
1,022 |
|
|
|
1,612 |
|
|
|
1 |
|
|
|
- |
|
|
|
- |
|
|
|
7 |
|
|
|
1,620 |
|
|
|
|
|
|
|
|
|
|
|
|
Basis of Netback Calculation |
|
|
|
|
|
|
|
Adjustments |
|
|
|
|
|
|
|
Per Interim
Consolidated
Financial
Statements (1) |
Nine Months Ended September 30, 2016
($ millions) |
|
Foster
Creek |
|
|
|
Christina
Lake |
|
|
|
Total
Crude Oil |
|
|
|
Natural Gas |
|
|
|
Condensate |
|
|
|
Inventory |
|
|
|
Other |
|
|
|
Total Oil
Sands |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross Sales |
|
490 |
|
|
|
476 |
|
|
|
966 |
|
|
|
9 |
|
|
|
994 |
|
|
|
- |
|
|
|
3 |
|
|
|
1,972 |
Less: Royalties |
|
2 |
|
|
|
5 |
|
|
|
7 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
7 |
|
|
488 |
|
|
|
471 |
|
|
|
959 |
|
|
|
9 |
|
|
|
994 |
|
|
|
- |
|
|
|
3 |
|
|
|
1,965 |
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transportation and Blending |
|
172 |
|
|
|
106 |
|
|
|
278 |
|
|
|
- |
|
|
|
994 |
|
|
|
(44) |
|
|
|
- |
|
|
|
1,228 |
Operating |
|
192 |
|
|
|
156 |
|
|
|
348 |
|
|
|
8 |
|
|
|
- |
|
|
|
- |
|
|
|
3 |
|
|
|
359 |
Netback |
|
124 |
|
|
|
209 |
|
|
|
333 |
|
|
|
1 |
|
|
|
- |
|
|
|
44 |
|
|
|
- |
|
|
|
378 |
(Gain) Loss on Risk Management |
|
(79) |
|
|
|
(85) |
|
|
|
(164) |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(1) |
|
|
|
(165) |
Operating Margin |
|
203 |
|
|
|
294 |
|
|
|
497 |
|
|
|
1 |
|
|
|
- |
|
|
|
44 |
|
|
|
1 |
|
|
|
543 |
(1) |
Found in Note 1 of the interim Consolidated Financial Statements. |
|
|
|
Cenovus Energy Inc.
Third Quarter 2017 Report |
|
Page 92
Netback Reconciliations |
Deep Basin
|
|
|
|
|
|
|
|
|
|
|
|
|
Basis of Netback Calculation |
|
|
|
Adjustments |
|
|
|
Per Interim
Consolidated
Financial Statements (1) |
Three Months Ended September 30, 2017 ($ millions) |
|
Total |
|
|
|
Other |
|
|
|
Total Deep Basin |
|
|
|
|
|
|
Revenues |
|
|
|
|
|
|
|
|
|
|
Gross Sales |
|
187 |
|
|
|
13 |
|
|
|
200 |
Less: Royalties |
|
13 |
|
|
|
- |
|
|
|
13 |
|
|
174 |
|
|
|
13 |
|
|
|
187 |
Expenses |
|
|
|
|
|
|
|
|
|
|
Transportation and Blending |
|
20 |
|
|
|
2 |
|
|
|
22 |
Operating |
|
96 |
|
|
|
5 |
|
|
|
101 |
Production and Mineral Taxes |
|
- |
|
|
|
- |
|
|
|
- |
Netback |
|
58 |
|
|
|
6 |
|
|
|
64 |
(Gain) Loss on Risk Management |
|
- |
|
|
|
- |
|
|
|
- |
Operating Margin |
|
58 |
|
|
|
6 |
|
|
|
64 |
|
|
|
|
|
|
|
|
Basis of Netback Calculation |
|
|
|
Adjustments |
|
|
|
Per Interim
Consolidated
Financial Statements (1) |
Nine Months Ended September 30, 2017 ($ millions) |
|
Total |
|
|
|
Other |
|
|
|
Total Deep Basin |
|
|
|
|
|
|
Revenues |
|
|
|
|
|
|
|
|
|
|
Gross Sales |
|
305 |
|
|
|
19 |
|
|
|
324 |
Less: Royalties |
|
21 |
|
|
|
- |
|
|
|
21 |
|
|
284 |
|
|
|
19 |
|
|
|
303 |
Expenses |
|
|
|
|
|
|
|
|
|
|
Transportation and Blending |
|
30 |
|
|
|
2 |
|
|
|
32 |
Operating |
|
143 |
|
|
|
9 |
|
|
|
152 |
Production and Mineral Taxes |
|
- |
|
|
|
- |
|
|
|
- |
Netback |
|
111 |
|
|
|
8 |
|
|
|
119 |
(Gain) Loss on Risk Management |
|
- |
|
|
|
- |
|
|
|
- |
Operating Margin |
|
111 |
|
|
|
8 |
|
|
|
119 |
(1) |
Found in Note 1 of the interim Consolidated Financial Statements. |
Conventional
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
Basis of Netback Calculation |
|
|
|
Adjustments |
|
|
|
Per Interim Consolidated Financial Statements (1)
|
September 30, 2017 ($
millions) |
|
Heavy Oil |
|
|
|
Light &
Medium |
|
|
|
NGLs |
|
|
|
Conventional
Liquids |
|
|
|
Natural
Gas |
|
|
|
Conventional |
|
|
|
Condensate |
|
|
|
Inventory |
|
|
|
Other |
|
|
|
Total
Conventional |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross Sales |
|
111 |
|
|
|
131 |
|
|
|
4 |
|
|
|
246 |
|
|
|
62 |
|
|
|
308 |
|
|
|
22 |
|
|
|
- |
|
|
|
1 |
|
|
|
331 |
Less: Royalties |
|
17 |
|
|
|
26 |
|
|
|
1 |
|
|
|
44 |
|
|
|
3 |
|
|
|
47 |
|
|
|
- |
|
|
|
- |
|
|
|
(2) |
|
|
|
45 |
|
|
94 |
|
|
|
105 |
|
|
|
3 |
|
|
|
202 |
|
|
|
59 |
|
|
|
261 |
|
|
|
22 |
|
|
|
- |
|
|
|
3 |
|
|
|
286 |
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transportation and Blending |
|
13 |
|
|
|
7 |
|
|
|
- |
|
|
|
20 |
|
|
|
3 |
|
|
|
23 |
|
|
|
22 |
|
|
|
- |
|
|
|
(1) |
|
|
|
44 |
Operating |
|
35 |
|
|
|
44 |
|
|
|
- |
|
|
|
79 |
|
|
|
39 |
|
|
|
118 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
118 |
Production and Mineral Taxes |
|
- |
|
|
|
4 |
|
|
|
- |
|
|
|
4 |
|
|
|
- |
|
|
|
4 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
4 |
Netback |
|
46 |
|
|
|
50 |
|
|
|
3 |
|
|
|
99 |
|
|
|
17 |
|
|
|
116 |
|
|
|
- |
|
|
|
- |
|
|
|
4 |
|
|
|
120 |
(Gain) Loss on Risk Management |
|
1 |
|
|
|
3 |
|
|
|
- |
|
|
|
4 |
|
|
|
(1) |
|
|
|
3 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
3 |
Operating Margin |
|
45 |
|
|
|
47 |
|
|
|
3 |
|
|
|
95 |
|
|
|
18 |
|
|
|
113 |
|
|
|
- |
|
|
|
- |
|
|
|
4 |
|
|
|
117 |
|
|
|
|
|
|
Three Months Ended |
|
Basis of Netback Calculation |
|
|
|
Adjustments |
|
|
|
Per Interim Consolidated Financial Statements
(1) |
September 30, 2016
($ millions) |
|
Heavy Oil |
|
|
|
Light &
Medium |
|
|
|
NGLs |
|
|
|
Conventional
Liquids |
|
|
|
Natural
Gas |
|
|
|
Conventional |
|
|
|
Condensate |
|
|
|
Inventory |
|
|
|
Other |
|
|
|
Total
Conventional |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross Sales |
|
104 |
|
|
|
114 |
|
|
|
3 |
|
|
|
221 |
|
|
|
86 |
|
|
|
307 |
|
|
|
21 |
|
|
|
- |
|
|
|
2 |
|
|
|
330 |
Less: Royalties |
|
10 |
|
|
|
21 |
|
|
|
1 |
|
|
|
32 |
|
|
|
3 |
|
|
|
35 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
35 |
|
|
94 |
|
|
|
93 |
|
|
|
2 |
|
|
|
189 |
|
|
|
83 |
|
|
|
272 |
|
|
|
21 |
|
|
|
- |
|
|
|
2 |
|
|
|
295 |
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transportation and Blending |
|
13 |
|
|
|
6 |
|
|
|
- |
|
|
|
19 |
|
|
|
4 |
|
|
|
23 |
|
|
|
21 |
|
|
|
- |
|
|
|
- |
|
|
|
44 |
Operating |
|
32 |
|
|
|
33 |
|
|
|
- |
|
|
|
65 |
|
|
|
35 |
|
|
|
100 |
|
|
|
- |
|
|
|
- |
|
|
|
2 |
|
|
|
102 |
Production and Mineral Taxes |
|
- |
|
|
|
4 |
|
|
|
- |
|
|
|
4 |
|
|
|
- |
|
|
|
4 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
4 |
Netback |
|
49 |
|
|
|
50 |
|
|
|
2 |
|
|
|
101 |
|
|
|
44 |
|
|
|
145 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
145 |
(Gain) Loss on Risk Management |
|
(5) |
|
|
|
(2) |
|
|
|
- |
|
|
|
(7) |
|
|
|
- |
|
|
|
(7) |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(7) |
Operating Margin |
|
54 |
|
|
|
52 |
|
|
|
2 |
|
|
|
108 |
|
|
|
44 |
|
|
|
152 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
152 |
(1) |
Found in Note 8 of the interim Consolidated Financial Statements. |
|
|
|
Cenovus Energy Inc.
Third Quarter 2017 Report |
|
Page 93
Netback Reconciliations |
Conventional
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended |
|
Basis of Netback Calculation |
|
|
|
Adjustments |
|
|
|
Per Interim Consolidated Financial Statements (1) |
September 30, 2017 ($
millions) |
|
Heavy Oil |
|
|
|
Light &
Medium |
|
|
|
NGLs |
|
|
|
Conventional
Liquids |
|
|
|
Natural
Gas |
|
|
|
Conventional |
|
|
|
Condensate |
|
|
|
Inventory |
|
|
|
Other |
|
|
|
Total
Conventional |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross Sales |
|
343 |
|
|
|
397 |
|
|
|
13 |
|
|
|
753 |
|
|
|
247 |
|
|
|
1,000 |
|
|
|
87 |
|
|
|
- |
|
|
|
4 |
|
|
|
1,091 |
Less: Royalties |
|
49 |
|
|
|
83 |
|
|
|
2 |
|
|
|
134 |
|
|
|
12 |
|
|
|
146 |
|
|
|
- |
|
|
|
- |
|
|
|
(1) |
|
|
|
145 |
|
|
294 |
|
|
|
314 |
|
|
|
11 |
|
|
|
619 |
|
|
|
235 |
|
|
|
854 |
|
|
|
87 |
|
|
|
- |
|
|
|
5 |
|
|
|
946 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transportation and Blending |
|
32 |
|
|
|
20 |
|
|
|
- |
|
|
|
52 |
|
|
|
10 |
|
|
|
62 |
|
|
|
87 |
|
|
|
- |
|
|
|
- |
|
|
|
149 |
Operating |
|
103 |
|
|
|
121 |
|
|
|
- |
|
|
|
224 |
|
|
|
117 |
|
|
|
341 |
|
|
|
- |
|
|
|
- |
|
|
|
2 |
|
|
|
343 |
Production and Mineral Taxes |
|
- |
|
|
|
13 |
|
|
|
- |
|
|
|
13 |
|
|
|
1 |
|
|
|
14 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
14 |
Netback |
|
159 |
|
|
|
160 |
|
|
|
11 |
|
|
|
330 |
|
|
|
107 |
|
|
|
437 |
|
|
|
- |
|
|
|
- |
|
|
|
3 |
|
|
|
440 |
(Gain) Loss on Risk Management |
|
10 |
|
|
|
10 |
|
|
|
- |
|
|
|
20 |
|
|
|
(1) |
|
|
|
19 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
19 |
Operating Margin |
|
149 |
|
|
|
150 |
|
|
|
11 |
|
|
|
310 |
|
|
|
108 |
|
|
|
418 |
|
|
|
- |
|
|
|
- |
|
|
|
3 |
|
|
|
421 |
|
|
|
|
|
|
Nine Months Ended |
|
Basis of Netback Calculation |
|
|
|
Adjustments |
|
|
|
Per
Interim Consolidated Financial Statements (1) |
September 30, 2016
($ millions) |
|
Heavy Oil |
|
|
|
Light &
Medium |
|
|
|
NGLs |
|
|
|
Conventional
Liquids |
|
|
|
Natural
Gas |
|
|
|
Conventional |
|
|
|
Condensate |
|
|
|
Inventory |
|
|
|
Other |
|
|
|
Total
Conventional |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross Sales |
|
272 |
|
|
|
315 |
|
|
|
7 |
|
|
|
594 |
|
|
|
221 |
|
|
|
815 |
|
|
|
76 |
|
|
|
- |
|
|
|
7 |
|
|
|
898 |
Less: Royalties |
|
24 |
|
|
|
54 |
|
|
|
2 |
|
|
|
80 |
|
|
|
8 |
|
|
|
88 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
88 |
|
|
248 |
|
|
|
261 |
|
|
|
5 |
|
|
|
514 |
|
|
|
213 |
|
|
|
727 |
|
|
|
76 |
|
|
|
- |
|
|
|
7 |
|
|
|
810 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transportation and Blending |
|
36 |
|
|
|
19 |
|
|
|
- |
|
|
|
55 |
|
|
|
12 |
|
|
|
67 |
|
|
|
76 |
|
|
|
(7) |
|
|
|
- |
|
|
|
136 |
Operating |
|
103 |
|
|
|
112 |
|
|
|
- |
|
|
|
215 |
|
|
|
113 |
|
|
|
328 |
|
|
|
- |
|
|
|
- |
|
|
|
3 |
|
|
|
331 |
Production and Mineral Taxes |
|
- |
|
|
|
9 |
|
|
|
- |
|
|
|
9 |
|
|
|
- |
|
|
|
9 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
9 |
Netback |
|
109 |
|
|
|
121 |
|
|
|
5 |
|
|
|
235 |
|
|
|
88 |
|
|
|
323 |
|
|
|
- |
|
|
|
7 |
|
|
|
4 |
|
|
|
334 |
(Gain) Loss on Risk Management |
|
(32) |
|
|
|
(28) |
|
|
|
- |
|
|
|
(60) |
|
|
|
1 |
|
|
|
(59) |
|
|
|
- |
|
|
|
- |
|
|
|
2 |
|
|
|
(57) |
Operating Margin |
|
141 |
|
|
|
149 |
|
|
|
5 |
|
|
|
295 |
|
|
|
87 |
|
|
|
382 |
|
|
|
- |
|
|
|
7 |
|
|
|
2 |
|
|
|
391 |
(1) |
Found in Note 8 of the interim Consolidated Financial Statements. |
The following table provides the sales volumes used to calculate Netback.
Sales Volumes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
|
|
Nine Months Ended September 30, |
(barrels per day, unless otherwise stated) |
|
2017 |
|
|
|
2016 |
|
|
|
2017 |
|
|
|
2016 |
|
|
|
|
|
|
|
|
Oil Sands |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foster Creek |
|
157,850 |
|
|
|
76,318 |
|
|
|
114,466 |
|
|
|
66,229 |
Christina Lake |
|
206,338 |
|
|
|
80,313 |
|
|
|
150,656 |
|
|
|
78,838 |
Total Oil Sands Crude Oil |
|
364,188 |
|
|
|
156,631 |
|
|
|
265,122 |
|
|
|
145,067 |
|
|
|
|
|
|
|
|
Natural Gas (MMcf per day) |
|
6 |
|
|
|
18 |
|
|
|
11 |
|
|
|
17 |
|
|
|
|
|
|
|
|
Deep Basin |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Liquids |
|
32,864 |
|
|
|
- |
|
|
|
16,706 |
|
|
|
- |
|
|
|
|
|
|
|
|
Natural Gas (MMcf per day) |
|
495 |
|
|
|
- |
|
|
|
251 |
|
|
|
- |
|
|
|
|
|
|
|
|
Conventional |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Heavy Oil |
|
25,047 |
|
|
|
27,953 |
|
|
|
26,448 |
|
|
|
28,999 |
Light and Medium Oil |
|
27,494 |
|
|
|
25,359 |
|
|
|
26,477 |
|
|
|
26,322 |
Natural Gas Liquids (NGLs) |
|
1,201 |
|
|
|
1,074 |
|
|
|
1,128 |
|
|
|
1,027 |
Total Conventional Liquids |
|
53,742 |
|
|
|
54,386 |
|
|
|
54,053 |
|
|
|
56,348 |
|
|
|
|
|
|
|
|
Natural Gas (MMcf per day) |
|
350 |
|
|
|
374 |
|
|
|
351 |
|
|
|
382 |
|
|
|
|
|
|
|
|
Total Liquids Sales |
|
450,794 |
|
|
|
211,017 |
|
|
|
335,881 |
|
|
|
201,415 |
|
|
|
|
|
|
|
|
Total Sales (BOE per day) |
|
592,591 |
|
|
|
276,350 |
|
|
|
438,028 |
|
|
|
267,915 |
|
|
|
Cenovus Energy Inc.
Third Quarter 2017 Report |
|
Page 94
Netback Reconciliations |
Cenovus Energy Inc.
500 Centre Street SE
PO Box 766
Calgary, AB T2P 0M5
Phone: 403-766-2000
Fax: 403-766-7600
|
|
|
CENOVUS CONTACTS |
|
|
|
|
Investor Relations: |
|
Media: |
|
|
Kam Sandhar |
|
General media line |
Vice-President, Investor Relations &
Corporate Development |
|
403-766-7751 |
403-766-5883 |
|
media.relations@cenovus.com |
kam.sandhar@cenovus.com |
|
|
Steven Murray
Manager, Investor Relations
403-766-3382
steven.murray@cenovus.com
Graham Ingram
Specialist, Investor Relations
403-766-2849
graham.ingram@cenovus.com
Michelle Cheyne
Analyst, Investor Relations
403-766-2584
michelle.cheyne@cenovus.com
cenovus.com
This regulatory filing also includes additional resources:
d417132dex9911.pdf
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