UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM10-Q
(Mark One)
[X] | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended September 30, 20172018
or
[ ] | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
Commission file number1-15226
ENCANA CORPORATION
(Exact name of registrant as specified in its charter)
Canada | 98-0355077 | |
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) |
Suite 4400, 500 Centre Street S.E., P.O. Box 2850, Calgary, Alberta, Canada, T2P 2S5
(Address of principal executive offices)
Registrant’s telephone number, including area code(403) 645-2000
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of RegulationS-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes [X] No [ ]
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, anon-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule12b-2 of the Exchange Act.
Large accelerated filer | [X] | Accelerated filer | [ ] | |||||
Non-accelerated filer | [ ] |
| Smaller reporting company | [ ] | ||||
Emerging growth company | [ ] |
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. [ ]
Indicate by check mark whether the registrant is a shell company (as defined in Rule12b-2 of the Exchange Act).
Yes [ ] No [X]
Number of registrant’s common shares outstanding as of | 952,478,421 |
FORM10-Q
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| 6 | ||||
| 6 | ||||
| 7 | ||||
| Condensed Consolidated Statement of Changes in Shareholders’ Equity | 8 | |||
| 9 | ||||
| 10 | ||||
Management’s Discussion and Analysis of Financial Condition and Results of Operations | 38 | ||||
60 | |||||
61 | |||||
62 | |||||
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64 | |||||
64 | |||||
64 | |||||
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65 | |||||
66 |
Unless the context otherwise indicates, references to “us,” “we,” “our,” “ours,” “Encana” and the “Company” refer to Encana Corporation and its consolidated subsidiaries. In addition, the following are other abbreviations and definitions of certain terms used within this Quarterly Report on Form10-Q:
“AECO” means Alberta Energy Company and is the Canadian benchmark price for natural gas.
“ASU” means Accounting Standards Update.
“bbl” or “bbls” means barrel or barrels.
“BOE” means barrels of oil equivalent.
“Btu” means British thermal units, a measure of heating value.
“DD&A” means depreciation, depletion and amortization expenses.
“FASB” means Financial Accounting Standards Board.
“Mbbls/d” means thousand barrels per day.
“MBOE/d” means thousand barrels of oil equivalent per day.
“Mcf” means thousand cubic feet.
“MD&A” means Management’s Discussion and Analysis of Financial Condition and Results of Operations.
“MMBOE” means million barrels of oil equivalent.
“MMBtu” means million Btu.
“MMcf/d” means million cubic feet per day.
“NCIB” means normal course issuer bid.
“NGL” or “NGLs” means natural gas liquids.
“NYMEX” means New York Mercantile Exchange.
“OPEC” means Organization of the Petroleum Exporting Countries.
“SEC” means United States Securities and Exchange Commission.
“TSX” means Toronto Stock Exchange.
“U.S.”, “United States” or “USA” means United States of America.
“U.S. GAAP” means U.S. Generally Accepted Accounting Principles.
“WTI” means West Texas Intermediate.
CONVERSIONS
In this Quarterly Report on Form10-Q, a conversion of natural gas volumes to BOE is on the basis of six Mcf to one bbl. BOE is based on a generic energy equivalency conversion method primarily applicable at the burner tip and does not represent economic value equivalency at the wellhead. Given that the value ratio based on the current price of oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value, particularly if used in isolation.
CONVENTIONS
Unless otherwise specified, all dollar amounts are expressed in U.S. dollars, all references to “dollars”, “$” or “US$” are to U.S. dollars and all references to “C$” are to Canadian dollars. All amounts are provided on a before tax basis, unless otherwise stated. In addition, all information provided herein is presented on an after royalties basis.
The term “liquids” is used to represent oil, NGLs and condensate. The term “liquids rich” is used to represent natural gas streams with associated liquids volumes. The term “play” is used to describe an area in which hydrocarbon accumulations or prospects of a given type occur. Encana’s focus of development is on hydrocarbon accumulations known to exist over a large areal expanse and/or thick vertical section and are developed using hydraulic fracturing. This type of development
typically has a lower geological and/or commercial development risk and lower average decline rate, when compared to conventional development.
The term “core asset” refers to plays that are the focus of the Company’s current capital investment and development plan. The Company continually reviews funding for development of its plays based on strategic fit, profitability and portfolio diversity and, as such, the composition of plays identified as a core asset may change over time.
References to information contained on the Company’s website atwww.encana.com are not incorporated by reference into, and does not constitute a part of, this Quarterly Report on Form10-Q.
FORWARD-LOOKING STATEMENTS AND RISK
This Quarterly Report on Form10-Q contains certain forward-looking statements or information (collectively, “forward-looking statements”) within the meaning of applicable securities legislation.legislation, including the United States Private Securities Litigation Reform Act of 1995. Forward-looking statements include: composition of the Company’s core assets, including allocation of capital and focus of development plans; growth in long-term shareholder value; vision of being a leading North American resource play company; statements with respect to the Company’s strategic objectives including capital allocation strategy, focus of investment, growth of high margin liquids volumes, operating and capital efficiencies ability to reduce costs and ability to preserve balance sheet strength; the Company’s drive for greater productivityability to lower costs and cost efficiencies; benefits fromimprove efficiencies to achieve competitive advantage; ability to repeat and deploy successful practices across the Company’s multi-basin portfolio; balancing commodity portfolio; anticipated commodity prices, productionprices; success of and product types;benefits from technology and innovation, including cube development approach and advanced completion designs; ability to accelerate activity levels and optimize well and completion designs; future well inventory; anticipated drilling, number of drilling rigs and the success thereof; anticipated drilling costs and cycle times; anticipated proceeds and future benefits from various joint venture, partnership and other agreements; expected timing for construction of compressionfacilities and processing capacity and its support of the Company’s growth plans;costs thereof; expansion of future midstream services; estimates of reserves and resources; success ofexpected production and benefits from technical innovation and cube development approach, including enhancements to productivity and recovery;product types; statements regarding anticipated returns, cash flow, non-GAAP cash flow margin and leverage ratios; anticipated cash and cash equivalents and use thereof;equivalents; anticipated hedging and outcomes of risk management program, including accessexposure to certain markets; potential rate escalationcommodity prices and foreign exchange, amount of transportation contracts;hedged production, market access and physical sales locations; impact of changes in laws and regulations, includingregulations; compliance with environmental legislation;legislation and claims related to the purported causes and impact of climate change, and the costs therefrom; adequacy of provisions for abandonment and site reclamation costs; financial flexibility and discipline; ability to meet financial obligations, manage debt and financial ratios, finance growth and compliance with financial covenants; impact to the Company as a result of changes to its credit rating; access to the Company’s credit facilities and other sources of financing;facilities; planned annualized dividend and the declaration and payment of future dividends, if any; the Company’s NCIB program, including amounts and number of shares to be acquired, anticipated timeframe, method and location of purchases, and source of funding thereof; adequacy of the Company’s provision for taxes and legal claims; successful resolution of certain tax items; projections and expectation of meeting the targets contained in the Company’s corporate guidance including updates thereto;and five-year plan; ability to manage cost inflation and expected cost structures, including expected operating, transportation and processing and administrative expenses; competitiveness and pace of growth of the Company’s assets within North America and against its peers; outlook of oil and gas industry generally and impact of geopolitical environment, including potential supply and demand factors; impact of weather; source of funding of capital spending plans;environment; expected future interest expense; the Company’s commitments and obligations and adjustments thereto; potential future discounts, if any, in connection with the Company’s dividend reinvestment program;anticipated payments thereunder; statements with respect to future ceiling test impairments; and the possible impact and timing of accounting pronouncements, rule changes and standards.standards; the timing of the closing of the sale of the Company’s San Juan assets and the expectation that closing conditions and regulatory approvals in respect thereof will be satisfied; and the timing of the closing of the acquisition of Newfield and the expectation that closing conditions in respect thereof, including shareholder and regulatory approvals, will be satisfied.
Readers are cautioned against unduly relying on forward-looking statements which, by their nature, involve numerous assumptions, risks and uncertainties that may cause such statements not to occur, or results to differ materially from those expressed or implied. These assumptions include: future commodity prices and differentials; foreign exchange rates; the Company’s ability to access its revolving credit facilities and shelf prospectuses; assumptions contained in the Company’s corporate guidance, five-year plan and as specified herein; data contained in key modeling statistics; availability of attractive hedges and enforceability of risk management program; effectiveness of the Company’s drive forto productivity and efficiencies; results from innovations; expectation that counterparties will fulfill their obligations under the gathering, midstream and marketing agreements; access to transportation and processing facilities where Encana operates; assumed tax, royalty and regulatory regimes; enforceability of transaction agreements; and expectations and projections made in light of, and generally consistent with, Encana’s historical experience and its perception of historical trends, including with respect to the pace of technological development, the benefits achieved and general industry expectations.
Risks and uncertainties that may affect these business outcomes include: the ability to generate sufficient cash flow to meet the Company’s obligations; commodity price volatility; ability to secure adequate product transportation and potential pipeline curtailments; variability and discretion of Encana’s board of directors (the “Board of Directors”) to declare and pay dividends, if any; the timing and costs of well, facilities and pipeline construction; business interruption, property and casualty losses or unexpected technical difficulties;difficulties, including impact of weather; counterparty and credit risk; risk and effectimpact of a downgrade in credit rating, including below an investment-grade credit rating and its impact on access to capital markets and other sources of liquidity; fluctuations in currency and interest rates; risks inherent in the Company’s corporate guidance; failure to achieve anticipated results from cost and efficiency initiatives; risks inherent in marketing operations; risks associated with technology; changes in or interpretation
of royalty, tax, environmental, greenhouse gas, carbon, accounting and other laws or regulations; risks associated with existing and potential future lawsuits and regulatory actions made against the Company; impact to the Company as a result of disputes arising with its partners, including the suspension by its partners of certain of their obligations and the inability to dispose of assets or interests in certain arrangements; the Company’s ability to acquire or find additional reserves; imprecision of reserves estimates and estimates of recoverable quantities, of natural gas and liquids from plays and other sources not currently classified as proved, probable or possible reserves or economic contingent resources, including future net revenue estimates; risks associated with past and future acquisitions or divestitures of certain assets or other transactions or receipt of amounts contemplated under the transaction agreements (such transactions may include third-party capital investments, farm-outs or partnerships, which Encana may refer to from time to time as “partnerships” or “joint ventures” and the funds received in respect thereof which Encana may refer to from time to time as “proceeds”, “deferred purchase price” and/or “carry capital”, regardless of the legal form) as a result of various conditions not being met; and other risks described herein and in Item 1A. Risk Factors of the Annual Report on Form10-K for the fiscal year ended December 31, 20162017 (“20162017 Annual Report on Form10-K”) and risks and uncertainties impacting Encana’sEncana's business as described from time to time in the Company’sCompany's other periodic filings with the SEC.
Although the Company believes the expectations represented by such forward-looking statements are reasonable, there can be no assurance that such expectations will prove to be correct. Readers are cautioned that the assumptions, risks and uncertainties referenced above are not exhaustive. Forward-looking statements are made as of the date of this document and, except as required by law, the Company undertakes no obligation to update publicly or revise any forward-looking statements. The forward-looking statements contained in this Quarterly Report on Form10-Q are expressly qualified by these cautionary statements.
The reader should read carefully the risk factors described herein and in Item 1A. Risk Factors of the 20162017 Annual Report on Form10-K for a description of certain risks that could, among other things, cause actual results to differ from these forward-looking statements.
PART I
Condensed Consolidated Statement of Earnings(unaudited)
|
|
|
| Three Months Ended |
|
| Nine Months Ended |
| ||||||||||
|
|
|
| September 30, |
|
| September 30, |
| ||||||||||
(US$ millions, except per share amounts) |
|
|
| 2018 |
|
| 2017 (1) |
|
| 2018 |
|
| 2017 (1) |
| ||||
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|
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|
|
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|
Revenues |
| (Notes 3, 4) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Product and service revenues |
|
|
| $ | 1,488 |
|
| $ | 880 |
|
| $ | 4,025 |
|
| $ | 2,751 |
|
Gains (losses) on risk management, net |
| (Note 19) |
|
| (241 | ) |
|
| (35 | ) |
|
| (517 | ) |
|
| 432 |
|
Sublease revenues |
|
|
|
| 15 |
|
|
| 16 |
|
|
| 50 |
|
|
| 50 |
|
Total Revenues |
|
|
|
| 1,262 |
|
|
| 861 |
|
|
| 3,558 |
|
|
| 3,233 |
|
Operating Expenses |
| (Note 3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production, mineral and other taxes |
|
|
|
| 45 |
|
|
| 27 |
|
|
| 109 |
|
|
| 80 |
|
Transportation and processing |
| (Note 19) |
|
| 278 |
|
|
| 199 |
|
|
| 799 |
|
|
| 617 |
|
Operating |
| (Notes 16, 17) |
|
| 124 |
|
|
| 132 |
|
|
| 372 |
|
|
| 377 |
|
Purchased product |
|
|
|
| 282 |
|
|
| 202 |
|
|
| 803 |
|
|
| 565 |
|
Depreciation, depletion and amortization |
|
|
|
| 349 |
|
|
| 210 |
|
|
| 924 |
|
|
| 590 |
|
Accretion of asset retirement obligation |
| (Note 12) |
|
| 8 |
|
|
| 9 |
|
|
| 24 |
|
|
| 30 |
|
Administrative |
| (Notes 16, 17) |
|
| 57 |
|
|
| 86 |
|
|
| 187 |
|
|
| 168 |
|
Total Operating Expenses |
|
|
|
| 1,143 |
|
|
| 865 |
|
|
| 3,218 |
|
|
| 2,427 |
|
Operating Income (Loss) |
|
|
|
| 119 |
|
|
| (4 | ) |
|
| 340 |
|
|
| 806 |
|
Other (Income) Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest |
| (Note 5) |
|
| 92 |
|
|
| 101 |
|
|
| 265 |
|
|
| 268 |
|
Foreign exchange (gain) loss, net |
| (Notes 6, 19) |
|
| (23 | ) |
|
| (210 | ) |
|
| 93 |
|
|
| (294 | ) |
(Gain) loss on divestitures, net |
| (Note 8) |
|
| - |
|
|
| (406 | ) |
|
| (4 | ) |
|
| (405 | ) |
Other (gains) losses, net |
| (Note 17) |
|
| 5 |
|
|
| (11 | ) |
|
| 2 |
|
|
| (46 | ) |
Total Other (Income) Expenses |
|
|
|
| 74 |
|
|
| (526 | ) |
|
| 356 |
|
|
| (477 | ) |
Net Earnings (Loss) Before Income Tax |
|
|
|
| 45 |
|
|
| 522 |
|
|
| (16 | ) |
|
| 1,283 |
|
Income tax expense (recovery) |
| (Note 7) |
|
| 6 |
|
|
| 228 |
|
|
| (55 | ) |
|
| 227 |
|
Net Earnings (Loss) |
|
|
| $ | 39 |
|
| $ | 294 |
|
| $ | 39 |
|
| $ | 1,056 |
|
Net Earnings (Loss) per Common Share |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic & Diluted |
| (Note 13) |
| $ | 0.04 |
|
| $ | 0.30 |
|
| $ | 0.04 |
|
| $ | 1.09 |
|
Dividends Declared per Common Share |
| (Note 13) |
| $ | 0.015 |
|
| $ | 0.015 |
|
| $ | 0.045 |
|
| $ | 0.045 |
|
Weighted Average Common Shares Outstanding (millions) |
|
|
|
|
|
|
|
|
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|
|
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|
|
|
Basic & Diluted |
| (Note 13) |
|
| 955.1 |
|
|
| 973.1 |
|
|
| 962.2 |
|
|
| 973.1 |
|
(1) | 2017 revenues have been realigned to conform with the January 1, 2018 adoption of ASU 2014-09 “Revenue from Contracts with Customers”. |
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||
(US$ millions, except per share amounts) | 2017 | 2016 | 2017 | 2016 | ||||||||||||||
Revenues | (Note 3) | |||||||||||||||||
Product revenues | $ | 646 | $ | 641 | $ | 2,112 | $ | 1,738 | ||||||||||
Gains (losses) on risk management, net | (Note 19) | (35) | 96 | 432 | (111) | |||||||||||||
Market optimization | 224 | 215 | 614 | 393 | ||||||||||||||
Other | 26 | 27 | 75 | 76 | ||||||||||||||
Total Revenues | 861 | 979 | 3,233 | 2,096 | ||||||||||||||
Operating Expenses | (Note 3) | |||||||||||||||||
Production, mineral and other taxes | 27 | 20 | 80 | 73 | ||||||||||||||
Transportation and processing | (Note 19) | 199 | 202 | 617 | 715 | |||||||||||||
Operating | 132 | 145 | 377 | 446 | ||||||||||||||
Purchased product | 202 | 197 | 565 | 349 | ||||||||||||||
Depreciation, depletion and amortization | 210 | 184 | 590 | 675 | ||||||||||||||
Impairments | (Note 8) | - | - | - | 1,396 | |||||||||||||
Accretion of asset retirement obligation | (Note 11) | 9 | 12 | 30 | 38 | |||||||||||||
Administrative | (Note 15) | 86 | 91 | 168 | 231 | |||||||||||||
Total Operating Expenses | 865 | 851 | 2,427 | 3,923 | ||||||||||||||
Operating Income (Loss) | (4) | 128 | 806 | (1,827) | ||||||||||||||
Other (Income) Expenses | ||||||||||||||||||
Interest | (Note 5) | 101 | 99 | 268 | 309 | |||||||||||||
Foreign exchange (gain) loss, net | (Notes 6, 19) | (210) | 49 | (294) | (307) | |||||||||||||
(Gain) loss on divestitures, net | (Note 4) | (406) | (395) | (405) | (393) | |||||||||||||
Other (gains) losses, net | (Note 9) | (11) | (4) | (46) | (67) | |||||||||||||
Total Other (Income) Expenses | (526) | (251) | (477) | (458) | ||||||||||||||
Net Earnings (Loss) Before Income Tax | 522 | 379 | 1,283 | (1,369) | ||||||||||||||
Income tax expense (recovery) | (Note 7) | 228 | 62 | 227 | (706) | |||||||||||||
Net Earnings (Loss) | $ | 294 | $ | 317 | $ | 1,056 | $ | (663) | ||||||||||
Net Earnings (Loss) per Common Share | ||||||||||||||||||
Basic & Diluted | (Note 12) | $ | 0.30 | $ | 0.37 | $ | 1.09 | $ | (0.78) | |||||||||
Dividends Declared per Common Share | (Note 12) | $ | 0.015 | $ | 0.015 | $ | 0.045 | $ | 0.045 | |||||||||
Weighted Average Common Shares Outstanding (millions) | ||||||||||||||||||
Basic & Diluted | (Note 12) | 973.1 | 858.3 | 973.1 | 852.7 |
Condensed Consolidated Statement of Comprehensive Income(unaudited)
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|
|
| Three Months Ended |
|
| Nine Months Ended |
| ||||||||||
|
|
|
| September 30, |
|
| September 30, |
| ||||||||||
(US$ millions) |
|
|
| 2018 |
|
| 2017 |
|
| 2018 |
|
| 2017 |
| ||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Earnings (Loss) |
|
|
| $ | 39 |
|
| $ | 294 |
|
| $ | 39 |
|
| $ | 1,056 |
|
Other Comprehensive Income (Loss), Net of Tax |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign currency translation adjustment |
| (Note 14) |
|
| 22 |
|
|
| (97 | ) |
|
| 21 |
|
|
| (172 | ) |
Pension and other post-employment benefit plans |
| (Notes 14, 17) |
|
| - |
|
|
| (1 | ) |
|
| (1 | ) |
|
| (2 | ) |
Other Comprehensive Income (Loss) |
|
|
|
| 22 |
|
|
| (98 | ) |
|
| 20 |
|
|
| (174 | ) |
Comprehensive Income (Loss) |
|
|
| $ | 61 |
|
| $ | 196 |
|
| $ | 59 |
|
| $ | 882 |
|
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||
(US$ millions) | 2017 | 2016 | 2017 | 2016 | ||||||||||||||
Net Earnings (Loss) | $ | 294 | $ | 317 | $ | 1,056 | $ | (663) | ||||||||||
Other Comprehensive Income (Loss), Net of Tax | ||||||||||||||||||
Foreign currency translation adjustment | (Note 13) | (97) | 36 | (172) | (220) | |||||||||||||
Pension and other post-employment benefit plans | (Notes 13, 17) | (1) | (1) | (2) | (1) | |||||||||||||
Other Comprehensive Income (Loss) | (98) | 35 | (174) | (221) | ||||||||||||||
Comprehensive Income (Loss) | $ | 196 | $ | 352 | $ | 882 | $ | (884) |
See accompanying Notes to Condensed Consolidated Financial Statements
6 |
Condensed Consolidated BalanceBalance Sheet(unaudited)
|
|
|
| As at |
|
| As at |
| ||
|
|
|
| September 30, |
|
| December 31, |
| ||
(US$ millions) |
|
|
| 2018 |
|
| 2017 |
| ||
|
|
|
|
|
|
|
|
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|
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Assets |
|
|
|
|
|
|
|
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|
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Current Assets |
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
|
| $ | 615 |
|
| $ | 719 |
|
Accounts receivable and accrued revenues |
|
|
|
| 835 |
|
|
| 774 |
|
Risk management |
| (Notes 18, 19) |
|
| 146 |
|
|
| 205 |
|
Income tax receivable |
|
|
|
| 290 |
|
|
| 573 |
|
|
|
|
|
| 1,886 |
|
|
| 2,271 |
|
Property, Plant and Equipment, at cost: |
| (Note 9) |
|
|
|
|
|
|
|
|
Oil and natural gas properties, based on full cost accounting |
|
|
|
|
|
|
|
|
|
|
Proved properties |
|
|
|
| 41,859 |
|
|
| 40,228 |
|
Unproved properties |
|
|
|
| 3,964 |
|
|
| 4,480 |
|
Other |
|
|
|
| 2,229 |
|
|
| 2,302 |
|
Property, plant and equipment |
|
|
|
| 48,052 |
|
|
| 47,010 |
|
Less: Accumulated depreciation, depletion and amortization |
|
|
|
| (38,519 | ) |
|
| (38,056 | ) |
Property, plant and equipment, net |
| (Note 3) |
|
| 9,533 |
|
|
| 8,954 |
|
Other Assets |
|
|
|
| 160 |
|
|
| 144 |
|
Risk Management |
| (Notes 18, 19) |
|
| 132 |
|
|
| 246 |
|
Deferred Income Taxes |
|
|
|
| 1,019 |
|
|
| 1,043 |
|
Goodwill |
| (Note 3) |
|
| 2,588 |
|
|
| 2,609 |
|
|
| (Note 3) |
| $ | 15,318 |
|
| $ | 15,267 |
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities and Shareholders’ Equity |
|
|
|
|
|
|
|
|
|
|
Current Liabilities |
|
|
|
|
|
|
|
|
|
|
Accounts payable and accrued liabilities |
|
|
| $ | 1,751 |
|
| $ | 1,415 |
|
Income tax payable |
|
|
|
| 1 |
|
|
| 7 |
|
Risk management |
| (Notes 18, 19) |
|
| 450 |
|
|
| 236 |
|
Current portion of long-term debt |
| (Note 10) |
|
| 500 |
|
|
| - |
|
|
|
|
|
| 2,702 |
|
|
| 1,658 |
|
Long-Term Debt |
| (Note 10) |
|
| 3,698 |
|
|
| 4,197 |
|
Other Liabilities and Provisions |
| (Note 11) |
|
| 1,916 |
|
|
| 2,167 |
|
Risk Management |
| (Notes 18, 19) |
|
| 68 |
|
|
| 13 |
|
Asset Retirement Obligation |
| (Note 12) |
|
| 407 |
|
|
| 470 |
|
Deferred Income Taxes |
|
|
|
| 33 |
|
|
| 34 |
|
|
|
|
|
| 8,824 |
|
|
| 8,539 |
|
Commitments and Contingencies |
| (Note 21) |
|
|
|
|
|
|
|
|
Shareholders’ Equity |
|
|
|
|
|
|
|
|
|
|
Share capital - authorized unlimited common shares |
|
|
|
|
|
|
|
|
|
|
2018 issued and outstanding: 952.4 million shares (2017: 973.1 million shares) |
| (Note 13) |
|
| 4,655 |
|
|
| 4,757 |
|
Paid in surplus |
|
|
|
| 1,358 |
|
|
| 1,358 |
|
Accumulated deficit |
|
|
|
| (581 | ) |
|
| (429 | ) |
Accumulated other comprehensive income |
| (Note 14) |
|
| 1,062 |
|
|
| 1,042 |
|
Total Shareholders’ Equity |
|
|
|
| 6,494 |
|
|
| 6,728 |
|
|
|
|
| $ | 15,318 |
|
| $ | 15,267 |
|
(US$ millions) | As at September 30, 2017 | As at December 31, 2016 | ||||||||
Assets | ||||||||||
Current Assets | ||||||||||
Cash and cash equivalents | $ | 889 | $ | 834 | ||||||
Accounts receivable and accrued revenues | 635 | 663 | ||||||||
Risk management | (Notes 18, 19) | 107 | - | |||||||
Income tax receivable | 579 | 426 | ||||||||
2,210 | 1,923 | |||||||||
Property, Plant and Equipment, at cost: | (Note 8) | |||||||||
Oil and natural gas properties, based on full cost accounting | ||||||||||
Proved properties | 39,588 | 39,610 | ||||||||
Unproved properties | 4,684 | 5,198 | ||||||||
Other | 2,312 | 2,194 | ||||||||
Property, plant and equipment | 46,584 | 47,002 | ||||||||
Less: Accumulated depreciation, depletion and amortization | (37,890) | (38,863) | ||||||||
Property, plant and equipment, net | (Note 3) | 8,694 | 8,139 | |||||||
Other Assets | 134 | 138 | ||||||||
Risk Management | (Notes 18, 19) | 84 | 16 | |||||||
Deferred Income Taxes | 1,429 | 1,658 | ||||||||
Goodwill | (Notes 3, 4) | 2,613 | 2,779 | |||||||
(Note 3) | $ | 15,164 | $ | 14,653 | ||||||
Liabilities and Shareholders’ Equity | ||||||||||
Current Liabilities | ||||||||||
Accounts payable and accrued liabilities | $ | 1,347 | $ | 1,303 | ||||||
Income tax payable | 6 | 5 | ||||||||
Risk management | (Notes 18, 19) | 17 | 254 | |||||||
1,370 | 1,562 | |||||||||
Long-Term Debt | (Note 9) | 4,197 | 4,198 | |||||||
Other Liabilities and Provisions | (Note 10) | 2,159 | 2,047 | |||||||
Risk Management | (Notes 18, 19) | 11 | 35 | |||||||
Asset Retirement Obligation | (Note 11) | 429 | 654 | |||||||
Deferred Income Taxes | 33 | 31 | ||||||||
8,199 | 8,527 | |||||||||
Commitments and Contingencies | (Note 21) | |||||||||
Shareholders’ Equity | ||||||||||
Share capital - authorized unlimited common shares 2017 issued and outstanding: 973.1 million shares (2016: 973.0 million shares) | (Note 12) | 4,757 | 4,756 | |||||||
Paid in surplus | 1,358 | 1,358 | ||||||||
Accumulated deficit | (186) | (1,198) | ||||||||
Accumulated other comprehensive income | (Note 13) | 1,036 | 1,210 | |||||||
Total Shareholders’ Equity | 6,965 | 6,126 | ||||||||
$ | 15,164 | $ | 14,653 |
See accompanying Notes to Condensed Consolidated Financial Statements
7 |
Condensed Consolidated Statement of ChangesChanges in Shareholders’ Equity(unaudited)
Nine Months Ended September 30, 2018 (US$ millions) |
|
|
| Share Capital |
|
| Paid in Surplus |
|
| Accumulated Deficit |
|
| Accumulated Other Comprehensive Income |
|
| Total Shareholders’ Equity |
| |||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2017 |
|
|
| $ | 4,757 |
|
| $ | 1,358 |
|
| $ | (429 | ) |
| $ | 1,042 |
|
| $ | 6,728 |
|
Net Earnings (Loss) |
|
|
|
| - |
|
|
| - |
|
|
| 39 |
|
|
| - |
|
|
| 39 |
|
Dividends on Common Shares |
| (Note 13) |
|
| - |
|
|
| - |
|
|
| (43 | ) |
|
| - |
|
|
| (43 | ) |
Common Shares Purchased under Normal Course Issuer Bid |
| (Note 13) |
|
| (102 | ) |
|
| - |
|
|
| (148 | ) |
|
| - |
|
|
| (250 | ) |
Common Shares Issued Under Dividend Reinvestment Plan |
| (Note 13) |
|
| - |
|
|
| - |
|
|
| - |
|
|
| - |
|
|
| - |
|
Other Comprehensive Income (Loss) |
| (Note 14) |
|
| - |
|
|
| - |
|
|
| - |
|
|
| 20 |
|
|
| 20 |
|
Balance, September 30, 2018 |
|
|
| $ | 4,655 |
|
| $ | 1,358 |
|
| $ | (581 | ) |
| $ | 1,062 |
|
| $ | 6,494 |
|
Nine Months Ended September 30, 2017 (US$ millions) | Nine Months Ended September 30, 2017 (US$ millions) | Share Capital | Paid in Surplus | Accumulated Deficit | Accumulated Other Comprehensive Income | Total Shareholders’ Equity |
|
|
| Share Capital |
|
| Paid in Surplus |
|
| Accumulated Deficit |
|
| Accumulated Other Comprehensive Income |
|
| Total Shareholders’ Equity |
| |||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||
Balance, December 31, 2016 | $ | 4,756 | $ | 1,358 | $ | (1,198) | $ | 1,210 | $ | 6,126 |
|
|
| $ | 4,756 |
|
| $ | 1,358 |
|
| $ | (1,198 | ) |
| $ | 1,210 |
|
| $ | 6,126 |
| ||||||||||||
Net Earnings (Loss) | - | - | 1,056 | - | 1,056 |
|
|
|
| - |
|
|
| - |
|
|
| 1,056 |
|
|
| - |
|
|
| 1,056 |
| |||||||||||||||||
Dividends on Common Shares | (Note 12) | - | - | (44) | - | (44) |
| (Note 13) |
|
| - |
|
|
| - |
|
|
| (44 | ) |
|
| - |
|
|
| (44 | ) | ||||||||||||||||
Common Shares Issued Under | (Note 12) | 1 | - | - | - | 1 |
| (Note 13) |
|
| 1 |
|
|
| - |
|
|
| - |
|
|
| - |
|
|
| 1 |
| ||||||||||||||||
Other Comprehensive Income (Loss) | (Note 13) | - | - | - | (174) | (174) |
| (Note 14) |
|
| - |
|
|
| - |
|
|
| - |
|
|
| (174 | ) |
|
| (174 | ) | ||||||||||||||||
Balance, September 30, 2017 | $ | 4,757 | $ | 1,358 | $ | (186) | $ | 1,036 | $ | 6,965 |
|
|
| $ | 4,757 |
|
| $ | 1,358 |
|
| $ | (186 | ) |
| $ | 1,036 |
|
| $ | 6,965 |
| ||||||||||||
Nine Months Ended September 30, 2016 (US$ millions) | Share Capital | Paid in Surplus | Accumulated Deficit | Accumulated Other Comprehensive Income | Total Shareholders’ Equity | |||||||||||||||||||||||||||||||||||||||
Balance, December 31, 2015 | $ | 3,621 | $ | 1,358 | $ | (202) | $ | 1,390 | $ | 6,167 | ||||||||||||||||||||||||||||||||||
Net Earnings (Loss) | - | - | (663) | - | �� | (663) | ||||||||||||||||||||||||||||||||||||||
Dividends on Common Shares | (Note 12) | - | - | (38) | - | (38) | ||||||||||||||||||||||||||||||||||||||
Common Shares Issued | (Note 12) | 986 | - | - | - | 986 | ||||||||||||||||||||||||||||||||||||||
Common Shares Issued Under | (Note 12) | 1 | - | - | - | 1 | ||||||||||||||||||||||||||||||||||||||
Other Comprehensive Income (Loss) | (Note 13) | - | - | - | (221) | (221) | ||||||||||||||||||||||||||||||||||||||
Balance, September 30, 2016 | $ | 4,608 | $ | 1,358 | $ | (903) | $ | 1,169 | $ | 6,232 |
See accompanying Notes to Condensed Consolidated Financial Statements
8 |
Condensed Consolidated StatementStatement of Cash Flows(unaudited)
|
|
|
| Three Months Ended |
|
| Nine Months Ended |
| ||||||||||
|
|
|
| September 30, |
|
| September 30, |
| ||||||||||
(US$ millions) |
|
|
| 2018 |
|
| 2017 |
|
| 2018 |
|
| 2017 |
| ||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings (loss) |
|
|
| $ | 39 |
|
| $ | 294 |
|
| $ | 39 |
|
| $ | 1,056 |
|
Depreciation, depletion and amortization |
|
|
|
| 349 |
|
|
| 210 |
|
|
| 924 |
|
|
| 590 |
|
Accretion of asset retirement obligation |
| (Note 12) |
|
| 8 |
|
|
| 9 |
|
|
| 24 |
|
|
| 30 |
|
Deferred income taxes |
| (Note 7) |
|
| 6 |
|
|
| 227 |
|
|
| 6 |
|
|
| 283 |
|
Unrealized (gain) loss on risk management |
| (Note 19) |
|
| 164 |
|
|
| 76 |
|
|
| 422 |
|
|
| (396 | ) |
Unrealized foreign exchange (gain) loss |
| (Note 6) |
|
| (23 | ) |
|
| (218 | ) |
|
| 156 |
|
|
| (317 | ) |
Foreign exchange on settlements |
| (Note 6) |
|
| (1 | ) |
|
| 18 |
|
|
| (47 | ) |
|
| 27 |
|
(Gain) loss on divestitures, net |
| (Note 8) |
|
| - |
|
|
| (406 | ) |
|
| (4 | ) |
|
| (405 | ) |
Other |
|
|
|
| 47 |
|
|
| 60 |
|
|
| 55 |
|
|
| 31 |
|
Net change in other assets and liabilities |
|
|
|
| (17 | ) |
|
| (11 | ) |
|
| (33 | ) |
|
| (27 | ) |
Net change in non-cash working capital |
| (Note 20) |
|
| 313 |
|
|
| 98 |
|
|
| 199 |
|
|
| (191 | ) |
Cash From (Used in) Operating Activities |
|
|
|
| 885 |
|
|
| 357 |
|
|
| 1,741 |
|
|
| 681 |
|
Investing Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures |
| (Note 3) |
|
| (523 | ) |
|
| (473 | ) |
|
| (1,626 | ) |
|
| (1,287 | ) |
Acquisitions |
| (Note 8) |
|
| (15 | ) |
|
| (2 | ) |
|
| (17 | ) |
|
| (50 | ) |
Proceeds from divestitures |
| (Note 8) |
|
| 24 |
|
|
| 625 |
|
|
| 89 |
|
|
| 710 |
|
Net change in investments and other |
|
|
|
| (8 | ) |
|
| 14 |
|
|
| 72 |
|
|
| 93 |
|
Cash From (Used in) Investing Activities |
|
|
|
| (522 | ) |
|
| 164 |
|
|
| (1,482 | ) |
|
| (534 | ) |
Financing Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchase of common shares |
| (Note 13) |
|
| (50 | ) |
|
| - |
|
|
| (250 | ) |
|
| - |
|
Dividends on common shares |
| (Note 13) |
|
| (14 | ) |
|
| (14 | ) |
|
| (43 | ) |
|
| (43 | ) |
Capital lease payments and other financing arrangements |
| (Note 11) |
|
| (23 | ) |
|
| (21 | ) |
|
| (68 | ) |
|
| (61 | ) |
Cash From (Used in) Financing Activities |
|
|
|
| (87 | ) |
|
| (35 | ) |
|
| (361 | ) |
|
| (104 | ) |
Foreign Exchange Gain (Loss) on Cash and Cash |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equivalents Held in Foreign Currency |
|
|
|
| 3 |
|
|
| 8 |
|
|
| (2 | ) |
|
| 12 |
|
Increase (Decrease) in Cash and Cash Equivalents |
|
|
|
| 279 |
|
|
| 494 |
|
|
| (104 | ) |
|
| 55 |
|
Cash and Cash Equivalents, Beginning of Period |
|
|
|
| 336 |
|
|
| 395 |
|
|
| 719 |
|
|
| 834 |
|
Cash and Cash Equivalents, End of Period |
|
|
| $ | 615 |
|
| $ | 889 |
|
| $ | 615 |
|
| $ | 889 |
|
Cash, End of Period |
|
|
| $ | 30 |
|
| $ | 39 |
|
| $ | 30 |
|
| $ | 39 |
|
Cash Equivalents, End of Period |
|
|
|
| 585 |
|
|
| 850 |
|
|
| 585 |
|
|
| 850 |
|
Cash and Cash Equivalents, End of Period |
|
|
| $ | 615 |
|
| $ | 889 |
|
| $ | 615 |
|
| $ | 889 |
|
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||
(US$ millions) |
2017 | 2016 |
2017 | 2016 | ||||||||||||||
Operating Activities | ||||||||||||||||||
Net earnings (loss) | $ | 294 | $ | 317 | $ | 1,056 | $ | (663) | ||||||||||
Depreciation, depletion and amortization | 210 | 184 | 590 | 675 | ||||||||||||||
Impairments | (Note 8) | - | - | - | 1,396 | |||||||||||||
Accretion of asset retirement obligation | (Note 11) | 9 | 12 | 30 | 38 | |||||||||||||
Deferred income taxes | (Note 7) | 227 | 76 | 283 | (683) | |||||||||||||
Unrealized (gain) loss on risk management | (Note 19) | 76 | (41) | (396) | 465 | |||||||||||||
Unrealized foreign exchange (gain) loss | (Note 6) | (218) | 47 | (317) | (223) | |||||||||||||
Foreign exchange on settlements | (Note 6) | 18 | (4) | 27 | (89) | |||||||||||||
(Gain) loss on divestitures, net | (Note 4) | (406) | (395) | (405) | (393) | |||||||||||||
Other | 60 | 56 | 31 | 13 | ||||||||||||||
Net change in other assets and liabilities | (11) | (6) | (27) | (15) | ||||||||||||||
Net change innon-cash working capital | (Note 20) | 98 | (60) | (191) | (95) | |||||||||||||
Cash From (Used in) Operating Activities | 357 | 186 | 681 | 426 | ||||||||||||||
Investing Activities | ||||||||||||||||||
Capital expenditures | (Note 3) | (473) | (205) | (1,287) | (779) | |||||||||||||
Acquisitions | (Note 4) | (2) | (67) | (50) | (69) | |||||||||||||
Proceeds from divestitures | (Note 4) | 625 | 1,107 | 710 | 1,113 | |||||||||||||
Net change in investments and other | 14 | (5) | 93 | (49) | ||||||||||||||
Cash From (Used in) Investing Activities | 164 | 830 | (534) | 216 | ||||||||||||||
Financing Activities | ||||||||||||||||||
Net issuance (repayment) of revolving long-term debt | - | (1,493) | - | (650) | ||||||||||||||
Repayment of long-term debt | (Note 9) | - | - | - | (400) | |||||||||||||
Issuance of common shares | (Note 12) | - | 981 | - | 981 | |||||||||||||
Dividends on common shares | (Note 12) | (14) | (13) | (43) | (37) | |||||||||||||
Capital lease payments and other financing arrangements | (Note 10) | (21) | (17) | (61) | (49) | |||||||||||||
Cash From (Used in) Financing Activities | (35) | (542) | (104) | (155) | ||||||||||||||
Foreign Exchange Gain (Loss) on Cash and Cash | ||||||||||||||||||
Equivalents Held in Foreign Currency | 8 | (1) | 12 | 8 | ||||||||||||||
Increase (Decrease) in Cash and Cash Equivalents | 494 | 473 | 55 | 495 | ||||||||||||||
Cash and Cash Equivalents, Beginning of Period | 395 | 293 | 834 | 271 | ||||||||||||||
Cash and Cash Equivalents, End of Period | $ | 889 | $ | 766 | $ | 889 | $ | 766 | ||||||||||
Cash, End of Period | $ | 39 | $ | 33 | $ | 39 | $ | 33 | ||||||||||
Cash Equivalents, End of Period | 850 | 733 | 850 | 733 | ||||||||||||||
Cash and Cash Equivalents, End of Period | $ | 889 | $ | 766 | $ | 889 | $ | 766 |
See accompanying Notes to Condensed Consolidated Financial Statements
9 |
Encana is in the business of the exploration for, the development of, and the production and marketing of oil, NGLs and natural gas.
The interim Condensed Consolidated Financial Statements include the accounts of Encana and entities in which it holds a controlling interest. All intercompany balances and transactions are eliminated on consolidation. Undivided interests in oil and natural gas exploration and production joint ventures and partnerships are consolidated on a proportionate basis. Investments innon-controlled entities over which Encana has the ability to exercise significant influence are accounted for using the equity method.
The interim Condensed Consolidated Financial Statements are prepared in conformity with U.S. GAAP and the rules and regulations of the SEC. Pursuant to these rules and regulations, certain information and disclosures normally required under U.S. GAAP have been condensed or have been disclosed on an annual basis only. Accordingly, the interim Condensed Consolidated Financial Statements should be read in conjunction with the annual audited Consolidated Financial Statements and the notes thereto for the year ended December 31, 2016,2017, which are included in Item 8 of Encana’s 20162017 Annual Report on Form10-K.
The interim Condensed Consolidated Financial Statements have been prepared following the same accounting policies and methods of computation as the annual audited Consolidated Financial Statements for the year ended December 31, 2017, except as noted below in Note 2. The disclosures provided below are incremental to those included with the annual audited Consolidated Financial Statements.
These unaudited interim Condensed Consolidated Financial Statements reflect, in the opinion of Management, all normal and recurring adjustments, with the exception of anout-of-period adjustment for the nine months ended September 30, 2017 as described in Note 6, which are necessary to present fairly the financial position and results of the Company as at and for the periods presented. Interim condensed consolidated financial results are not necessarily indicative of consolidated financial results expected for the fiscal year.
. Recent Accounting Pronouncements
2. |
|
New Standards Issued Not Yet Adopted
As ofChanges in Accounting Policies and Practices
On January 1, 2018, Encana will be required to adopt adopted the following ASUs issued by the FASB, which have not had a material impact on the Company's interim Condensed Consolidated Financial Statements:
ASU2014-09, “Revenue from Contracts with Customers” under Topic 606 and the related subsequent updates and clarifications issued, which will replace606. The new standard replaces Topic 605, “Revenue Recognition”, and as well as other industry-specific guidance inwithin the Accounting Standards Codification. The new standardTopic 606 is based on the principle that revenue is recognized on the transfer of promised goods or services to customers in an amount that reflects the consideration the company expects to be entitled to in exchange for those goods or services. In August 2015, the FASB issued ASU2015-14, “Deferral of Effective Date for Revenue from Contracts with Customers”, which deferred the effective date of ASU2014-09.The standard can behas been applied using either the full retrospective approach or a modified retrospective approach at the date of adoption. Encana has substantially completed evaluating the impact of ASU2014-09and currently expects that the standard willdid not have a material impact on the Company’s Condensed Consolidated Financial Statements, other than enhancedenhancing disclosures related to the disaggregation of revenues from contracts with customers the Company’sand performance obligations and any significant judgments. Encana intends to adopt the new standard using the modified retrospective approach at the date of adoption.
As of January 1, 2018, Encana will beobligations. The disclosures required to adopt under Topic 606 are included in Note 4, Revenues from Contracts with Customers.
ASU2017-07, “Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost”. The amendment requires the service cost component to be presented with the related employee compensation costs, while the other components of net benefit costs are required to be presented separately from the service cost component and outside the subtotal of income from operations. In addition, the amendment allows only the service cost to be eligible for capitalization. The amendment will behas been applied retrospectively and provides certain practical expedients for the presentation of net periodic pension costs and net periodic postretirement benefit cost, whilewhereas prospective adoption has been applied to the capitalization of the service cost component will be applied prospectively, at the date of adoption. Encana does not expect the amendment to have a material impact on the Company’s Consolidated Financial Statements.component.
10 |
New Standards Issued Not Yet Adopted
As of January 1, 2019, Encana will be required to adopt ASU2016-02, “Leases” under Topic 842, which will replace Topic 840 “Leases”. The new standard will require lessees to recognizeright-of-use assets and related lease liabilities for all leases, including leases classified as operating leases, on the Consolidated Balance Sheet. The dual classification model was retained for the purpose of subsequent measurementHowever, Topic 842 provides a short-term lease exemption which does not require a right-of-use asset and presentation of leases inlease liability to be recognized on the Consolidated Statement of Earnings and Consolidated Statement of Cash Flows. The new standardBalance Sheet when the lease term is 12 months or less, including any renewal periods which are reasonably certain to be exercised. Encana intends to elect the short-term lease exemption. Topic 842 also expands disclosures related to the amount, timing and uncertainty of cash flows arising from leases. The standard will
In July 2018, FASB issued ASU 2018-11, “Targeted Improvements”, providing entities the option to apply Topic 842 at the adoption date recognizing a cumulative effect adjustment to the opening balance of retained earnings in the period of adoption, while the comparative periods presented would continue to be applied using a modified retrospective approach and provides forin accordance with Topic 840. Encana intends to elect this optional transition method, as well as certain practical expedients atpermitted under Topic 842, which will allow the dateCompany to retain the classification of leases assessed under Topic 840 that commenced prior to adoption. Encana is currently identifying, gatheringalso intends to adopt the transitional practical expedient provided under ASU 2018-01, “Land Easement Practical Expedient for Transition to Topic 842” issued by FASB in January 2018. This amendment applies to land easements that existed or expired prior to adoption of Topic 842 and analyzing contracts impacted by thewere not previously accounted for as leases under Topic 840. The expedient provides prospective application of Topic 842 to all new or modified land easements upon adoption of the new standard,standard.
Encana continues to review and analyze contracts, identify its portfolio of leased assets, gather the necessary terms and data elements, as well as evaluatingidentify the processes and controls required to support the accounting for leases and related disclosures. The Company is in the process of implementing and testing a lease software system requirementswhich will facilitate the measurement and required disclosures for implementation.operating leases. The Company anticipates the software implementation to be complete by the end of 2018, at which time Encana expects to begin quantifying the impact of adopting Topic 842. Although Encana is not able to reasonably estimate the financial impact of ASU2016-02Topic 842 at this time, the Company anticipates there will be an increase in right-of-use assets and lease liabilities on the Consolidated Balance Sheet.
As of January 1, 2019, Encana will be required to adopt ASU 2018-02 “Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income”. The amendments allow for a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Cuts and Jobs Act (“U.S. Tax Reform”). Amendments can be applied either in the period of adoption or retrospectively to each period in which the effect of the rate change from the U.S. Tax Reform is recognized. While Encana has other post-employment benefit plans which were affected by the U.S. Tax Reform, the impact is not material impact onto the Company’s Consolidated Financial Statements resulting fromStatements. As a result, the recognition of assets and liabilities relatedCompany does not intend to operating lease activities.take the election provided in the amendment.
As of January 1, 2020, Encana will be required to adopt ASU2017-04, “Simplifying the Test for Goodwill Impairment”. The amendment eliminates the second step of the goodwill impairment test which requires the Company to measure the impairment based on the excess amount of the carrying value of the reporting unit’s goodwill over the implied fair value of its goodwill. Under this amendment, the goodwill impairment will be measured based on the excess amount of the reporting unit’s carrying value over its respective fair value. The amendment will be applied prospectively at the date of adoption. Encana is currently in the early stages of reviewing the amendment, but does not expect the amendment to have a material impact on the Company’s Consolidated Financial Statements.
11 |
Encana’s reportable segments are determined based on the Company’s operations and geographic locations as follows:
Canadian Operations includes the exploration for, development of, and production of oil, NGLs and natural gas and other related activities within the Canadian cost centre.
|
USA Operations includes the exploration for, development of, and production of oil, NGLs and natural gas and other related activities within the U.S. cost centre.
|
Market Optimization is primarily responsible for the sale of the Company’s proprietary production. These results are reported in the Canadian and USA Operations. Market optimization activities include third party purchases and sales of product to provide operational flexibility and cost mitigation for transportation commitments, product type, delivery points and customer diversification. These activities are reflected in the Market Optimization segment. Market Optimization sells substantially all of the Company’s upstream production to third party customers. Transactions between segments are based on market values and are eliminated on consolidation.
|
Corporate and Other mainly includes unrealized gains or losses recorded on derivative financial instruments. Once the instruments are settled, the realized gains and losses are recorded in the reporting segment to which the derivative instruments relate. Corporate and Other also includes amounts related to sublease rentals.
12 |
Results of Operations (For the three months ended September 30)
Segment and Geographic Information
Canadian Operations | USA Operations | Market Optimization |
| Canadian Operations |
|
| USA Operations |
|
| Market Optimization |
| |||||||||||||||||||||||||||||||||||||
2017 | 2016 | 2017 | 2016 | 2017 | 2016 |
| 2018 |
|
| 2017 (1) |
|
| 2018 |
|
| 2017 (1) |
|
| 2018 |
|
| 2017 (1) |
| |||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||||
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||||||||
Product revenues | $ | 226 | $ | 244 | $ | 420 | $ | 397 | $ | - | $ | - | ||||||||||||||||||||||||||||||||||||
Product and service revenues |
| $ | 453 |
|
| $ | 235 |
|
| $ | 718 |
|
| $ | 421 |
|
| $ | 317 |
|
| $ | 224 |
| ||||||||||||||||||||||||
Gains (losses) on risk management, net | 25 | - | 16 | 55 | - | (1) |
|
| 8 |
|
|
| 25 |
|
|
| (84 | ) |
|
| 16 |
|
|
| (1 | ) |
|
| - |
| ||||||||||||||||||
Market optimization | - | - | - | - | 224 | 215 | ||||||||||||||||||||||||||||||||||||||||||
Other | 9 | 2 | 1 | 6 | - | - | ||||||||||||||||||||||||||||||||||||||||||
Sublease revenues |
|
| - |
|
|
| - |
|
|
| - |
|
|
| - |
|
|
| - |
|
|
| - |
| ||||||||||||||||||||||||
Total Revenues | 260 | 246 | 437 | 458 | 224 | 214 |
|
| 461 |
|
|
| 260 |
|
|
| 634 |
|
|
| 437 |
|
|
| 316 |
|
|
| 224 |
| ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||||
Operating Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||||||||
Production, mineral and other taxes | 6 | 5 | 21 | 15 | - | - |
|
| 4 |
|
|
| 6 |
|
|
| 41 |
|
|
| 21 |
|
|
| - |
|
|
| - |
| ||||||||||||||||||
Transportation and processing | 138 | 136 | 31 | 43 | 30 | 22 |
|
| 211 |
|
|
| 138 |
|
|
| 34 |
|
|
| 31 |
|
|
| 33 |
|
|
| 30 |
| ||||||||||||||||||
Operating | 36 | 38 | 81 | 93 | 11 | 11 |
|
| 34 |
|
|
| 36 |
|
|
| 80 |
|
|
| 81 |
|
|
| 8 |
|
|
| 11 |
| ||||||||||||||||||
Purchased product | - | - | - | - | 202 | 197 |
|
| - |
|
|
| - |
|
|
| - |
|
|
| - |
|
|
| 282 |
|
|
| 202 |
| ||||||||||||||||||
Depreciation, depletion and amortization | 53 | 54 | 139 | 112 | 1 | - |
|
| 95 |
|
|
| 53 |
|
|
| 241 |
|
|
| 139 |
|
|
| - |
|
|
| 1 |
| ||||||||||||||||||
Impairments | - | - | - | - | - | - | ||||||||||||||||||||||||||||||||||||||||||
Total Operating Expenses | 233 | 233 | 272 | 263 | 244 | 230 |
|
| 344 |
|
|
| 233 |
|
|
| 396 |
|
|
| 272 |
|
|
| 323 |
|
|
| 244 |
| ||||||||||||||||||
Operating Income (Loss) | $ | 27 | $ | 13 | $ | 165 | $ | 195 | $ | (20) | $ | (16) |
| $ | 117 |
|
| $ | 27 |
|
| $ | 238 |
|
| $ | 165 |
|
| $ | (7 | ) |
| $ | (20 | ) | ||||||||||||
Corporate & Other | Consolidated | |||||||||||||||||||||||||||||||||||||||||||||||
2017 | 2016 | 2017 | 2016 | |||||||||||||||||||||||||||||||||||||||||||||
Revenues | ||||||||||||||||||||||||||||||||||||||||||||||||
Product revenues | $ | - | $ | - | $ | 646 | $ | 641 | ||||||||||||||||||||||||||||||||||||||||
Gains (losses) on risk management, net | (76) | 42 | (35) | 96 | ||||||||||||||||||||||||||||||||||||||||||||
Market optimization | - | - | 224 | 215 | ||||||||||||||||||||||||||||||||||||||||||||
Other | 16 | 19 | 26 | 27 | ||||||||||||||||||||||||||||||||||||||||||||
Total Revenues | (60) | 61 | 861 | 979 | ||||||||||||||||||||||||||||||||||||||||||||
Operating Expenses | ||||||||||||||||||||||||||||||||||||||||||||||||
Production, mineral and other taxes | - | - | 27 | 20 | ||||||||||||||||||||||||||||||||||||||||||||
Transportation and processing | - | 1 | 199 | 202 | ||||||||||||||||||||||||||||||||||||||||||||
Operating | 4 | 3 | 132 | 145 | ||||||||||||||||||||||||||||||||||||||||||||
Purchased product | - | - | 202 | 197 | ||||||||||||||||||||||||||||||||||||||||||||
Depreciation, depletion and amortization | 17 | 18 | 210 | 184 | ||||||||||||||||||||||||||||||||||||||||||||
Impairments | - | - | - | - | ||||||||||||||||||||||||||||||||||||||||||||
Accretion of asset retirement obligation | 9 | 12 | 9 | 12 | ||||||||||||||||||||||||||||||||||||||||||||
Administrative | 86 | 91 | 86 | 91 | ||||||||||||||||||||||||||||||||||||||||||||
Total Operating Expenses | 116 | 125 | 865 | 851 | ||||||||||||||||||||||||||||||||||||||||||||
Operating Income (Loss) | $ | (176) | $ | (64) | (4) | 128 | ||||||||||||||||||||||||||||||||||||||||||
Other (Income) Expenses | ||||||||||||||||||||||||||||||||||||||||||||||||
Interest | 101 | 99 | ||||||||||||||||||||||||||||||||||||||||||||||
Foreign exchange (gain) loss, net | (210) | 49 | ||||||||||||||||||||||||||||||||||||||||||||||
(Gain) loss on divestitures, net | (406) | (395) | ||||||||||||||||||||||||||||||||||||||||||||||
Other (gains) losses, net | (11) | (4) | ||||||||||||||||||||||||||||||||||||||||||||||
Total Other (Income) Expenses | (526) | (251) | ||||||||||||||||||||||||||||||||||||||||||||||
Net Earnings (Loss) Before Income Tax | 522 | 379 | ||||||||||||||||||||||||||||||||||||||||||||||
Income tax expense (recovery) | 228 | 62 | ||||||||||||||||||||||||||||||||||||||||||||||
Net Earnings (Loss) | $ | 294 | $ | 317 |
|
|
|
|
|
| Corporate & Other |
|
| Consolidated |
| ||||||||||
|
|
|
|
|
| 2018 |
|
| 2017 (1) |
|
| 2018 |
|
| 2017 (1) |
| ||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Product and service revenues |
|
|
|
|
| $ | - |
|
| $ | - |
|
| $ | 1,488 |
|
| $ | 880 |
|
Gains (losses) on risk management, net |
|
|
|
|
|
| (164 | ) |
|
| (76 | ) |
|
| (241 | ) |
|
| (35 | ) |
Sublease revenues |
|
|
|
|
|
| 15 |
|
|
| 16 |
|
|
| 15 |
|
|
| 16 |
|
Total Revenues |
|
|
|
|
|
| (149 | ) |
|
| (60 | ) |
|
| 1,262 |
|
|
| 861 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production, mineral and other taxes |
|
|
|
|
|
| - |
|
|
| - |
|
|
| 45 |
|
|
| 27 |
|
Transportation and processing |
|
|
|
|
|
| - |
|
|
| - |
|
|
| 278 |
|
|
| 199 |
|
Operating |
|
|
|
|
|
| 2 |
|
|
| 4 |
|
|
| 124 |
|
|
| 132 |
|
Purchased product |
|
|
|
|
|
| - |
|
|
| - |
|
|
| 282 |
|
|
| 202 |
|
Depreciation, depletion and amortization |
|
|
|
|
|
| 13 |
|
|
| 17 |
|
|
| 349 |
|
|
| 210 |
|
Accretion of asset retirement obligation |
|
|
|
|
|
| 8 |
|
|
| 9 |
|
|
| 8 |
|
|
| 9 |
|
Administrative |
|
|
|
|
|
| 57 |
|
|
| 86 |
|
|
| 57 |
|
|
| 86 |
|
Total Operating Expenses |
|
|
|
|
|
| 80 |
|
|
| 116 |
|
|
| 1,143 |
|
|
| 865 |
|
Operating Income (Loss) |
|
|
|
|
| $ | (229 | ) |
| $ | (176 | ) |
|
| 119 |
|
|
| (4 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other (Income) Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest |
|
|
|
|
|
|
|
|
|
|
|
|
|
| 92 |
|
|
| 101 |
|
Foreign exchange (gain) loss, net |
|
|
|
|
|
|
|
|
|
|
|
|
|
| (23 | ) |
|
| (210 | ) |
(Gain) loss on divestitures, net |
|
|
|
|
|
|
|
|
|
|
|
|
|
| - |
|
|
| (406 | ) |
Other (gains) losses, net |
|
|
|
|
|
|
|
|
|
|
|
|
|
| 5 |
|
|
| (11 | ) |
Total Other (Income) Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
| 74 |
|
|
| (526 | ) |
Net Earnings (Loss) Before Income Tax |
|
|
|
|
|
|
|
|
|
|
|
|
|
| 45 |
|
|
| 522 |
|
Income tax expense (recovery) |
|
|
|
|
|
|
|
|
|
|
|
|
|
| 6 |
|
|
| 228 |
|
Net Earnings (Loss) |
|
|
|
|
|
|
|
|
|
|
|
|
| $ | 39 |
|
| $ | 294 |
|
(1) | 2017 revenues have been realigned to conform with the January 1, 2018 adoption of ASU 2014-09 “Revenue from Contracts with Customers”. |
13 |
Results of Operations (For the nine months ended September 30)
Segment and Geographic Information
Canadian Operations | USA Operations | Market Optimization |
| Canadian Operations |
|
| USA Operations |
|
| Market Optimization |
| |||||||||||||||||||||||||||||||||||||
2017 | 2016 | 2017 | 2016 | 2017 | 2016 |
| 2018 |
|
| 2017 (1) |
|
| 2018 |
|
| 2017 (1) |
|
| 2018 |
|
| 2017 (1) |
| |||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||||
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||||||||
Product revenues | $ | 787 | $ | 664 | $ | 1,325 | $ | 1,074 | $ | - | $ | - | ||||||||||||||||||||||||||||||||||||
Product and service revenues |
| $ | 1,236 |
|
| $ | 801 |
|
| $ | 1,880 |
|
| $ | 1,336 |
|
| $ | 909 |
|
| $ | 614 |
| ||||||||||||||||||||||||
Gains (losses) on risk management, net | 6 | 122 | 30 | 236 | - | - |
|
| 93 |
|
|
| 6 |
|
|
| (185 | ) |
|
| 30 |
|
|
| (3 | ) |
|
| - |
| ||||||||||||||||||
Market optimization | - | - | - | - | 614 | 393 | ||||||||||||||||||||||||||||||||||||||||||
Other | 14 | 6 | 11 | 17 | - | - | ||||||||||||||||||||||||||||||||||||||||||
Sublease revenues |
|
| - |
|
|
| - |
|
|
| - |
|
|
| - |
|
|
| - |
|
|
| - |
| ||||||||||||||||||||||||
Total Revenues | 807 | 792 | 1,366 | 1,327 | 614 | 393 |
|
| 1,329 |
|
|
| 807 |
|
|
| 1,695 |
|
|
| 1,366 |
|
|
| 906 |
|
|
| 614 |
| ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||||
Operating Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||||||||
Production, mineral and other taxes | 16 | 17 | 64 | 56 | - | - |
|
| 12 |
|
|
| 16 |
|
|
| 97 |
|
|
| 64 |
|
|
| - |
|
|
| - |
| ||||||||||||||||||
Transportation and processing | 403 | 440 | 141 | 214 | 73 | 65 |
|
| 608 |
|
|
| 403 |
|
|
| 92 |
|
|
| 141 |
|
|
| 99 |
|
|
| 73 |
| ||||||||||||||||||
Operating | 89 | 115 | 252 | 293 | 23 | 25 |
|
| 98 |
|
|
| 89 |
|
|
| 238 |
|
|
| 252 |
|
|
| 25 |
|
|
| 23 |
| ||||||||||||||||||
Purchased product | - | - | - | - | 565 | 349 |
|
| - |
|
|
| - |
|
|
| - |
|
|
| - |
|
|
| 803 |
|
|
| 565 |
| ||||||||||||||||||
Depreciation, depletion and amortization | 170 | 203 | 368 | 414 | 1 | - |
|
| 257 |
|
|
| 170 |
|
|
| 628 |
|
|
| 368 |
|
|
| 1 |
|
|
| 1 |
| ||||||||||||||||||
Impairments | - | 493 | - | 903 | - | - | ||||||||||||||||||||||||||||||||||||||||||
Total Operating Expenses | 678 | 1,268 | 825 | 1,880 | 662 | 439 |
|
| 975 |
|
|
| 678 |
|
|
| 1,055 |
|
|
| 825 |
|
|
| 928 |
|
|
| 662 |
| ||||||||||||||||||
Operating Income (Loss) | $ | 129 | $ | (476 | ) | $ | 541 | $ | (553 | ) | $ | (48) | $ (46 | ) |
| $ | 354 |
|
| $ | 129 |
|
| $ | 640 |
|
| $ | 541 |
|
| $ | (22 | ) |
| $ | (48 | ) | ||||||||||
Corporate & Other | Consolidated | |||||||||||||||||||||||||||||||||||||||||||||||
2017 | 2016 | 2017 | 2016 | |||||||||||||||||||||||||||||||||||||||||||||
Revenues | ||||||||||||||||||||||||||||||||||||||||||||||||
Product revenues | $ | - | $ | - | $ | 2,112 | $ | 1,738 | ||||||||||||||||||||||||||||||||||||||||
Gains (losses) on risk management, net | 396 | (469 | ) | 432 | (111 | ) | ||||||||||||||||||||||||||||||||||||||||||
Market optimization | - | - | 614 | 393 | ||||||||||||||||||||||||||||||||||||||||||||
Other | 50 | 53 | 75 | 76 | ||||||||||||||||||||||||||||||||||||||||||||
Total Revenues | 446 | (416 | ) | 3,233 | 2,096 | |||||||||||||||||||||||||||||||||||||||||||
Operating Expenses | ||||||||||||||||||||||||||||||||||||||||||||||||
Production, mineral and other taxes | - | - | 80 | 73 | ||||||||||||||||||||||||||||||||||||||||||||
Transportation and processing | - | (4) | 617 | 715 | ||||||||||||||||||||||||||||||||||||||||||||
Operating | 13 | 13 | 377 | 446 | ||||||||||||||||||||||||||||||||||||||||||||
Purchased product | - | - | 565 | 349 | ||||||||||||||||||||||||||||||||||||||||||||
Depreciation, depletion and amortization | 51 | 58 | 590 | 675 | ||||||||||||||||||||||||||||||||||||||||||||
Impairments | - | - | - | 1,396 | ||||||||||||||||||||||||||||||||||||||||||||
Accretion of asset retirement obligation | 30 | 38 | 30 | 38 | ||||||||||||||||||||||||||||||||||||||||||||
Administrative | 168 | 231 | 168 | 231 | ||||||||||||||||||||||||||||||||||||||||||||
Total Operating Expenses | 262 | 336 | 2,427 | 3,923 | ||||||||||||||||||||||||||||||||||||||||||||
Operating Income (Loss) | $ | 184 | $ | (752 | ) | 806 | (1,827) | |||||||||||||||||||||||||||||||||||||||||
Other (Income) Expenses | ||||||||||||||||||||||||||||||||||||||||||||||||
Interest | 268 | 309 | ||||||||||||||||||||||||||||||||||||||||||||||
Foreign exchange (gain) loss, net | (294 | ) | (307 | ) | ||||||||||||||||||||||||||||||||||||||||||||
(Gain) loss on divestitures, net | (405 | ) | (393 | ) | ||||||||||||||||||||||||||||||||||||||||||||
Other (gains) losses, net | (46 | ) | (67 | ) | ||||||||||||||||||||||||||||||||||||||||||||
Total Other (Income) Expenses | (477 | ) | (458 | ) | ||||||||||||||||||||||||||||||||||||||||||||
Net Earnings (Loss) Before Income Tax | 1,283 | (1,369 | ) | |||||||||||||||||||||||||||||||||||||||||||||
Income tax expense (recovery) | 227 | (706 | ) | |||||||||||||||||||||||||||||||||||||||||||||
Net Earnings (Loss) | $ | 1,056 | $ | (663 | ) |
|
|
|
|
|
| Corporate & Other |
|
| Consolidated |
| ||||||||||
|
|
|
|
|
| 2018 |
|
| 2017 (1) |
|
| 2018 |
|
| 2017 (1) |
| ||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Product and service revenues |
|
|
|
|
| $ | - |
|
| $ | - |
|
| $ | 4,025 |
|
| $ | 2,751 |
|
Gains (losses) on risk management, net |
|
|
|
|
|
| (422 | ) |
|
| 396 |
|
|
| (517 | ) |
|
| 432 |
|
Sublease revenues |
|
|
|
|
|
| 50 |
|
|
| 50 |
|
|
| 50 |
|
|
| 50 |
|
Total Revenues |
|
|
|
|
|
| (372 | ) |
|
| 446 |
|
|
| 3,558 |
|
|
| 3,233 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production, mineral and other taxes |
|
|
|
|
|
| - |
|
|
| - |
|
|
| 109 |
|
|
| 80 |
|
Transportation and processing |
|
|
|
|
|
| - |
|
|
| - |
|
|
| 799 |
|
|
| 617 |
|
Operating |
|
|
|
|
|
| 11 |
|
|
| 13 |
|
|
| 372 |
|
|
| 377 |
|
Purchased product |
|
|
|
|
|
| - |
|
|
| - |
|
|
| 803 |
|
|
| 565 |
|
Depreciation, depletion and amortization |
|
|
|
|
|
| 38 |
|
|
| 51 |
|
|
| 924 |
|
|
| 590 |
|
Accretion of asset retirement obligation |
|
|
|
|
|
| 24 |
|
|
| 30 |
|
|
| 24 |
|
|
| 30 |
|
Administrative |
|
|
|
|
|
| 187 |
|
|
| 168 |
|
|
| 187 |
|
|
| 168 |
|
Total Operating Expenses |
|
|
|
|
|
| 260 |
|
|
| 262 |
|
|
| 3,218 |
|
|
| 2,427 |
|
Operating Income (Loss) |
|
|
|
|
| $ | (632 | ) |
| $ | 184 |
|
|
| 340 |
|
|
| 806 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other (Income) Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest |
|
|
|
|
|
|
|
|
|
|
|
|
|
| 265 |
|
|
| 268 |
|
Foreign exchange (gain) loss, net |
|
|
|
|
|
|
|
|
|
|
|
|
|
| 93 |
|
|
| (294 | ) |
(Gain) loss on divestitures, net |
|
|
|
|
|
|
|
|
|
|
|
|
|
| (4 | ) |
|
| (405 | ) |
Other (gains) losses, net |
|
|
|
|
|
|
|
|
|
|
|
|
|
| 2 |
|
|
| (46 | ) |
Total Other (Income) Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
| 356 |
|
|
| (477 | ) |
Net Earnings (Loss) Before Income Tax |
|
|
|
|
|
|
|
|
|
|
|
|
|
| (16 | ) |
|
| 1,283 |
|
Income tax expense (recovery) |
|
|
|
|
|
|
|
|
|
|
|
|
|
| (55 | ) |
|
| 227 |
|
Net Earnings (Loss) |
|
|
|
|
|
|
|
|
|
|
|
|
| $ | 39 |
|
| $ | 1,056 |
|
(1) | 2017 revenues have been realigned to conform with the January 1, 2018 adoption of ASU 2014-09 “Revenue from Contracts with Customers”. |
14 |
|
|
|
|
|
|
|
|
| Market Optimization |
|
|
|
|
|
|
|
|
| ||||||||||||||||||||||||||||||
Market Optimization |
| Marketing Sales |
|
| Upstream Eliminations |
|
| Total |
| |||||||||||||||||||||||||||||||||||||||
Marketing Sales | Upstream Eliminations | Total | ||||||||||||||||||||||||||||||||||||||||||||||
For the three months ended September 30 | 2017 | 2016 | 2017 | 2016 | 2017 | 2016 | ||||||||||||||||||||||||||||||||||||||||||
For the three months ended September 30, |
| 2018 |
|
| 2017 |
|
| 2018 |
|
| 2017 |
|
| 2018 |
|
| 2017 |
| ||||||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||||
Revenues | $ | 918 | $ | 963 | $ | (694) | $ | (749) | $ | 224 | $ | 214 |
| $ | 1,513 |
|
| $ | 918 |
|
| $ | (1,197 | ) |
| $ | (694 | ) |
| $ | 316 |
|
| $ | 224 |
| ||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||||
Operating Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||||||||
Transportation and processing | 72 | 65 | (42) | (43) | 30 | 22 |
|
| 120 |
|
|
| 72 |
|
|
| (87 | ) |
|
| (42 | ) |
|
| 33 |
|
|
| 30 |
| ||||||||||||||||||
Operating | 11 | 11 | - | - | 11 | 11 |
|
| 8 |
|
|
| 11 |
|
|
| - |
|
|
| - |
|
|
| 8 |
|
|
| 11 |
| ||||||||||||||||||
Purchased product | 854 | 904 | (652) | (707) | 202 | 197 |
|
| 1,392 |
|
|
| 854 |
|
|
| (1,110 | ) |
|
| (652 | ) |
|
| 282 |
|
|
| 202 |
| ||||||||||||||||||
Depreciation, depletion and amortization | 1 | - | - | - | 1 | - |
|
| - |
|
|
| 1 |
|
|
| - |
|
|
| - |
|
|
| - |
|
|
| 1 |
| ||||||||||||||||||
Operating Income (Loss) | $ | (20) | $ | (17) | $ | - | $ | 1 | $ | (20) | $ | (16) |
| $ | (7 | ) |
| $ | (20 | ) |
| $ | - |
|
| $ | - |
|
| $ | (7 | ) |
| $ | (20 | ) | ||||||||||||
Market Optimization | ||||||||||||||||||||||||||||||||||||||||||||||||
Marketing Sales | Upstream Eliminations | Total | ||||||||||||||||||||||||||||||||||||||||||||||
For the nine months ended September 30 | 2017 | 2016 | 2017 | 2016 | 2017 | 2016 | ||||||||||||||||||||||||||||||||||||||||||
Revenues | $ | 2,825 | $ | 2,365 | $ | (2,211) | $ | (1,972) | $ | 614 | $ | 393 | ||||||||||||||||||||||||||||||||||||
Operating Expenses | ||||||||||||||||||||||||||||||||||||||||||||||||
Transportation and processing | 197 | 219 | (124) | (154) | 73 | 65 | ||||||||||||||||||||||||||||||||||||||||||
Operating | 23 | 25 | - | - | 23 | 25 | ||||||||||||||||||||||||||||||||||||||||||
Purchased product | 2,652 | 2,167 | (2,087) | (1,818) | 565 | 349 | ||||||||||||||||||||||||||||||||||||||||||
Depreciation, depletion and amortization | 1 | - | - | - | 1 | - | ||||||||||||||||||||||||||||||||||||||||||
Operating Income (Loss) | $ | (48) | $ | (46) | $ | - | $ | - | $ | (48) | $ | (46) | ||||||||||||||||||||||||||||||||||||
Capital Expenditures | ||||||||||||||||||||||||||||||||||||||||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||||||||||||||||||||||||||||||||
2017 | 2016 | 2017 | 2016 | |||||||||||||||||||||||||||||||||||||||||||||
Canadian Operations | $ | 123 | $ | 56 | $ | 292 | $ | 173 | ||||||||||||||||||||||||||||||||||||||||
USA Operations | 347 | 149 | 991 | 605 | ||||||||||||||||||||||||||||||||||||||||||||
Market Optimization | 1 | 1 | 1 | 1 | ||||||||||||||||||||||||||||||||||||||||||||
Corporate & Other | 2 | (1 | ) | 3 | - | |||||||||||||||||||||||||||||||||||||||||||
$ | 473 | $ | 205 | $ | 1,287 | $ | 779 | |||||||||||||||||||||||||||||||||||||||||
Goodwill, Property, Plant and Equipment and Total Assets by Segment
|
| |||||||||||||||||||||||||||||||||||||||||||||||
Goodwill | Property, Plant and Equipment | Total Assets | ||||||||||||||||||||||||||||||||||||||||||||||
As at | As at | As at | ||||||||||||||||||||||||||||||||||||||||||||||
September 30, 2017 | December 31, 2016 | September 30, 2017 | December 31, 2016 | September 30, 2017 | December 31, 2016 | |||||||||||||||||||||||||||||||||||||||||||
Canadian Operations | $ | 700 | $ | 650 | $ | 780 | $ | 602 | $ | 1,787 | $ | 1,542 | ||||||||||||||||||||||||||||||||||||
USA Operations | 1,913 | 2,129 | 6,363 | 6,050 | 9,461 | 9,535 | ||||||||||||||||||||||||||||||||||||||||||
Market Optimization | - | - | 2 | 2 | 119 | 105 | ||||||||||||||||||||||||||||||||||||||||||
Corporate & Other | - | - | 1,549 | 1,485 | 3,797 | 3,471 | ||||||||||||||||||||||||||||||||||||||||||
$ | 2,613 | $ | 2,779 | $ | 8,694 | $ | 8,139 | $ | 15,164 | $ | 14,653 |
|
| Market Optimization |
| |||||||||||||||||||||
|
| Marketing Sales |
|
| Upstream Eliminations |
|
| Total |
| |||||||||||||||
For the nine months ended September 30, |
| 2018 |
|
| 2017 |
|
| 2018 |
|
| 2017 |
|
| 2018 |
|
| 2017 |
| ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
| $ | 4,203 |
|
| $ | 2,825 |
|
| $ | (3,297 | ) |
| $ | (2,211 | ) |
| $ | 906 |
|
| $ | 614 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transportation and processing |
|
| 335 |
|
|
| 197 |
|
|
| (236 | ) |
|
| (124 | ) |
|
| 99 |
|
|
| 73 |
|
Operating |
|
| 25 |
|
|
| 23 |
|
|
| - |
|
|
| - |
|
|
| 25 |
|
|
| 23 |
|
Purchased product |
|
| 3,864 |
|
|
| 2,652 |
|
|
| (3,061 | ) |
|
| (2,087 | ) |
|
| 803 |
|
|
| 565 |
|
Depreciation, depletion and amortization |
|
| 1 |
|
|
| 1 |
|
|
| - |
|
|
| - |
|
|
| 1 |
|
|
| 1 |
|
Operating Income (Loss) |
| $ | (22 | ) |
| $ | (48 | ) |
| $ | - |
|
| $ | - |
|
| $ | (22 | ) |
| $ | (48 | ) |
Capital Expenditures
|
|
|
|
|
| Three Months Ended |
|
| Nine Months Ended |
| ||||||||||
|
|
|
|
|
| September 30, |
|
| September 30, |
| ||||||||||
|
|
|
|
|
| 2018 |
|
| 2017 |
|
| 2018 |
|
| 2017 |
| ||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
|
|
|
| $ | 174 |
|
| $ | 123 |
|
| $ | 553 |
|
| $ | 292 |
|
USA Operations |
|
|
|
|
|
| 345 |
|
|
| 347 |
|
|
| 1,065 |
|
|
| 991 |
|
Market Optimization |
|
|
|
|
|
| - |
|
|
| 1 |
|
|
| - |
|
|
| 1 |
|
Corporate & Other |
|
|
|
|
|
| 4 |
|
|
| 2 |
|
|
| 8 |
|
|
| 3 |
|
|
|
|
|
|
| $ | 523 |
|
| $ | 473 |
|
| $ | 1,626 |
|
| $ | 1,287 |
|
Goodwill, Property, Plant and Equipment and Total Assets by Segment
|
| Goodwill |
|
| Property, Plant and Equipment |
|
| Total Assets |
| |||||||||||||||
|
| As at |
|
| As at |
|
| As at |
| |||||||||||||||
|
| September 30, |
| December 31, |
|
| September 30, |
| December 31, |
|
| September 30, |
| December 31, |
| |||||||||
|
| 2018 |
|
| 2017 |
|
| 2018 |
|
| 2017 |
|
| 2018 |
|
| 2017 |
| ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
| $ | 675 |
|
| $ | 696 |
|
| $ | 1,098 |
|
| $ | 862 |
|
| $ | 2,064 |
|
| $ | 1,908 |
|
USA Operations |
|
| 1,913 |
|
|
| 1,913 |
|
|
| 6,973 |
|
|
| 6,555 |
|
|
| 9,744 |
|
|
| 9,301 |
|
Market Optimization |
|
| - |
|
|
| - |
|
|
| 1 |
|
|
| 2 |
|
|
| 199 |
|
|
| 152 |
|
Corporate & Other |
|
| - |
|
|
| - |
|
|
| 1,461 |
|
|
| 1,535 |
|
|
| 3,311 |
|
|
| 3,906 |
|
|
| $ | 2,588 |
|
| $ | 2,609 |
|
| $ | 9,533 |
|
| $ | 8,954 |
|
| $ | 15,318 |
|
| $ | 15,267 |
|
15 |
The following tables summarize the Company’s revenues from contracts with customers and other sources of revenues. Encana presents realized and unrealized gains and losses on certain derivative contracts within revenues.
Revenues (For the three months ended September 30)
|
| Canadian Operations |
|
| USA Operations |
|
| Market Optimization |
| |||||||||||||||
|
| 2018 |
|
| 2017 |
|
| 2018 |
|
| 2017 |
|
| 2018 |
|
| 2017 |
| ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues from Customers |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Product revenues (1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
| $ | 1 |
|
| $ | 2 |
|
| $ | 590 |
|
| $ | 319 |
|
| $ | 34 |
|
| $ | 15 |
|
NGLs |
|
| 259 |
|
|
| 107 |
|
|
| 98 |
|
|
| 50 |
|
|
| 1 |
|
|
| - |
|
Natural gas |
|
| 195 |
|
|
| 126 |
|
|
| 31 |
|
|
| 58 |
|
|
| 274 |
|
|
| 199 |
|
Service revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering and processing |
|
| 1 |
|
|
| 3 |
|
|
| 4 |
|
|
| 1 |
|
|
| - |
|
|
| - |
|
Product and Service Revenues |
|
| 456 |
|
|
| 238 |
|
|
| 723 |
|
|
| 428 |
|
|
| 309 |
|
|
| 214 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gains (losses) on risk management, net (2) |
|
| 8 |
|
|
| 25 |
|
|
| (84 | ) |
|
| 16 |
|
|
| (1 | ) |
|
| - |
|
Sublease revenues |
|
| - |
|
|
| - |
|
|
| - |
|
|
| - |
|
|
| - |
|
|
| - |
|
Other Revenues |
|
| 8 |
|
|
| 25 |
|
|
| (84 | ) |
|
| 16 |
|
|
| (1 | ) |
|
| - |
|
Total Revenues |
| $ | 464 |
|
| $ | 263 |
|
| $ | 639 |
|
| $ | 444 |
|
| $ | 308 |
|
| $ | 214 |
|
|
|
|
|
|
| Corporate & Other |
|
| Consolidated |
| ||||||||||
|
|
|
|
|
| 2018 |
|
| 2017 |
|
| 2018 |
|
| 2017 |
| ||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues from Customers |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Product revenues (1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
|
|
|
| $ | - |
|
| $ | - |
|
| $ | 625 |
|
| $ | 336 |
|
NGLs |
|
|
|
|
|
| - |
|
|
| - |
|
|
| 358 |
|
|
| 157 |
|
Natural gas |
|
|
|
|
|
| - |
|
|
| - |
|
|
| 500 |
|
|
| 383 |
|
Service revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering and processing |
|
|
|
|
|
| - |
|
|
| - |
|
|
| 5 |
|
|
| 4 |
|
Product and Service Revenues |
|
|
|
|
|
| - |
|
|
| - |
|
|
| 1,488 |
|
|
| 880 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gains (losses) on risk management, net (2) |
|
|
|
|
|
| (164 | ) |
|
| (76 | ) |
|
| (241 | ) |
|
| (35 | ) |
Sublease revenues |
|
|
|
|
|
| 15 |
|
|
| 16 |
|
|
| 15 |
|
|
| 16 |
|
Other Revenues |
|
|
|
|
|
| (149 | ) |
|
| (60 | ) |
|
| (226 | ) |
|
| (19 | ) |
Total Revenues |
|
|
|
|
| $ | (149 | ) |
| $ | (60 | ) |
| $ | 1,262 |
|
| $ | 861 |
|
(1) | Includes revenues from production and revenues of product purchased from third parties, but excludes intercompany marketing fees transacted between the Company’s operating segments. |
(2) | Canadian Operations, USA Operations and Market Optimization include realized gains/(losses) on risk management. Corporate & Other includes unrealized gains/(losses) on risk management. |
16 |
Revenues (For the nine months ended September 30)
|
| Canadian Operations |
|
| USA Operations |
|
| Market Optimization |
| |||||||||||||||
|
| 2018 |
|
| 2017 |
|
| 2018 |
|
| 2017 |
|
| 2018 |
|
| 2017 |
| ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues from Customers |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Product revenues (1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
| $ | 6 |
|
| $ | 5 |
|
| $ | 1,579 |
|
| $ | 944 |
|
| $ | 84 |
|
| $ | 103 |
|
NGLs |
|
| 655 |
|
|
| 300 |
|
|
| 221 |
|
|
| 128 |
|
|
| 6 |
|
|
| 12 |
|
Natural gas |
|
| 580 |
|
|
| 498 |
|
|
| 92 |
|
|
| 268 |
|
|
| 793 |
|
|
| 475 |
|
Service revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering and processing |
|
| 5 |
|
|
| 7 |
|
|
| 4 |
|
|
| 11 |
|
|
| - |
|
|
| - |
|
Product and Service Revenues |
|
| 1,246 |
|
|
| 810 |
|
|
| 1,896 |
|
|
| 1,351 |
|
|
| 883 |
|
|
| 590 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gains (losses) on risk management, net (2) |
|
| 93 |
|
|
| 6 |
|
|
| (185 | ) |
|
| 30 |
|
|
| (3 | ) |
|
| - |
|
Sublease revenues |
|
| - |
|
|
| - |
|
|
| - |
|
|
| - |
|
|
| - |
|
|
| - |
|
Other Revenues |
|
| 93 |
|
|
| 6 |
|
|
| (185 | ) |
|
| 30 |
|
|
| (3 | ) |
|
| - |
|
Total Revenues |
| $ | 1,339 |
|
| $ | 816 |
|
| $ | 1,711 |
|
| $ | 1,381 |
|
| $ | 880 |
|
| $ | 590 |
|
|
|
|
|
|
| Corporate & Other |
|
| Consolidated |
| ||||||||||
|
|
|
|
|
| 2018 |
|
| 2017 |
|
| 2018 |
|
| 2017 |
| ||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues from Customers |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Product revenues (1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
|
|
|
| $ | - |
|
| $ | - |
|
| $ | 1,669 |
|
| $ | 1,052 |
|
NGLs |
|
|
|
|
|
| - |
|
|
| - |
|
|
| 882 |
|
|
| 440 |
|
Natural gas |
|
|
|
|
|
| - |
|
|
| - |
|
|
| 1,465 |
|
|
| 1,241 |
|
Service revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering and processing |
|
|
|
|
|
| - |
|
|
| - |
|
|
| 9 |
|
|
| 18 |
|
Product and Service Revenues |
|
|
|
|
|
| - |
|
|
| - |
|
|
| 4,025 |
|
|
| 2,751 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gains (losses) on risk management, net (2) |
|
|
|
|
|
| (422 | ) |
|
| 396 |
|
|
| (517 | ) |
|
| 432 |
|
Sublease revenues |
|
|
|
|
|
| 50 |
|
|
| 50 |
|
|
| 50 |
|
|
| 50 |
|
Other Revenues |
|
|
|
|
|
| (372 | ) |
|
| 446 |
|
|
| (467 | ) |
|
| 482 |
|
Total Revenues |
|
|
|
|
| $ | (372 | ) |
| $ | 446 |
|
| $ | 3,558 |
|
| $ | 3,233 |
|
(1) | Includes revenues from production and revenues of product purchased from third parties, but excludes intercompany marketing fees transacted between the Company’s operating segments. |
(2) | Canadian Operations, USA Operations and Market Optimization include realized gains/(losses) on risk management. Corporate & Other includes unrealized gains/(losses) on risk management. |
The Company’s revenues from contracts with customers consists of product sales including oil, NGLs and natural gas, as well as the provision of gathering and processing services to third parties. Encana had no contract asset or liability balances during the periods presented. As at September 30, 2018, receivables and accrued revenues from contracts with customers were $764 million ($676 million as at December 31, 2017).
Performance obligations arising from product sales contracts are typically satisfied at a point in time when the product is delivered to the customer and control is transferred. Payment from the customer is due when the product is delivered to the custody point. The Company’s product sales are sold under short-term contracts with terms that are less than one year at either fixed or market index prices or under long-term contracts exceeding one year at market index prices.
As at September 30, 2018, all remaining performance obligations are priced at market index prices or are variable volume delivery contracts. As such, the variable consideration is allocated entirely to the wholly unsatisfied performance obligation or promise to deliver units of production, and revenue is recognized at the amount for which the Company has the right to invoice the product delivered.
Performance obligations arising from arrangements to gather and process natural gas on behalf of third parties are typically satisfied over time as the service is provided to the customer. Payment from the customer is due when the customer receives the benefit of the service and the product is delivered to the custody point or plant tailgate. The Company’s gathering and processing services are provided on an interruptible basis with transaction prices that are for fixed prices and/or variable
17 |
consideration. Variable consideration received is related to recovery of plant operating costs or escalation of the fixed price based on a consumer price index. As the service contracts are interruptible, with service provided on an “as available” basis, there are no unsatisfied performance obligations remaining at September 30, 2018.
5. | Interest |
|
| Three Months Ended |
|
| Nine Months Ended |
| ||||||||||
|
| September 30, |
|
| September 30, |
| ||||||||||
|
| 2018 |
|
| 2017 |
|
| 2018 |
|
| 2017 |
| ||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest Expense on: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Debt |
| $ | 67 |
|
| $ | 67 |
|
| $ | 200 |
|
| $ | 200 |
|
The Bow office building |
|
| 16 |
|
|
| 16 |
|
|
| 48 |
|
|
| 47 |
|
Capital leases |
|
| 3 |
|
|
| 6 |
|
|
| 12 |
|
|
| 16 |
|
Other |
|
| 6 |
|
|
| 12 |
|
|
| 5 |
|
|
| 5 |
|
|
| $ | 92 |
|
| $ | 101 |
|
| $ | 265 |
|
| $ | 268 |
|
6. | Foreign Exchange (Gain) Loss, Net |
|
| Three Months Ended |
|
| Nine Months Ended |
| ||||||||||
|
| September 30, |
|
| September 30, |
| ||||||||||
|
| 2018 |
|
| 2017 |
|
| 2018 |
|
| 2017 |
| ||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized Foreign Exchange (Gain) Loss on: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Translation of U.S. dollar financing debt issued from Canada |
| $ | (74 | ) |
| $ | (187 | ) |
| $ | 138 |
|
| $ | (265 | ) |
Translation of U.S. dollar risk management contracts issued from Canada |
|
| (3 | ) |
|
| (21 | ) |
|
| 7 |
|
|
| (53 | ) |
Translation of intercompany notes |
|
| 54 |
|
|
| (10 | ) |
|
| 11 |
|
|
| 1 |
|
|
|
| (23 | ) |
|
| (218 | ) |
|
| 156 |
|
|
| (317 | ) |
Foreign Exchange on Settlements of: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. dollar financing debt issued from Canada |
|
| - |
|
|
| 3 |
|
|
| 1 |
|
|
| 10 |
|
U.S. dollar risk management contracts issued from Canada |
|
| (1 | ) |
|
| (9 | ) |
|
| (11 | ) |
|
| (8 | ) |
Intercompany notes |
|
| (1 | ) |
|
| 15 |
|
|
| (48 | ) |
|
| 17 |
|
Other Monetary Revaluations |
|
| 2 |
|
|
| (1 | ) |
|
| (5 | ) |
|
| 4 |
|
|
| $ | (23 | ) |
| $ | (210 | ) |
| $ | 93 |
|
| $ | (294 | ) |
The unrealized foreign exchange (gain) loss on translation of U.S. dollar financing debt issued from Canada for the nine months ended September 30, 2017 disclosed in the table above included an out-of-period adjustment in respect of unrealized losses on a foreign-denominated capital lease obligation since December 2013. The cumulative impact recognized within foreign exchange (gain) loss in the Company’s Condensed Consolidated Statement of Earnings for the nine months ended September 30, 2017 was $68 million, before tax ($47 million, after tax). Encana determined that the adjustment was not material to the Condensed Consolidated Financial Statements for the period ended September 30, 2017 or any prior periods.
18 |
|
| Three Months Ended |
|
| Nine Months Ended |
| ||||||||||
|
| September 30, |
|
| September 30, |
| ||||||||||
|
| 2018 |
|
| 2017 |
|
| 2018 |
|
| 2017 |
| ||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current Tax |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada |
| $ | - |
|
| $ | - |
|
| $ | (66 | ) |
| $ | (62 | ) |
United States |
|
| - |
|
|
| 1 |
|
|
| 2 |
|
|
| 2 |
|
Other Countries |
|
| - |
|
|
| - |
|
|
| 3 |
|
|
| 4 |
|
Total Current Tax Expense (Recovery) |
|
| - |
|
|
| 1 |
|
|
| (61 | ) |
|
| (56 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred Tax |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada |
|
| 19 |
|
|
| 71 |
|
|
| (9 | ) |
|
| 91 |
|
United States |
|
| (3 | ) |
|
| 101 |
|
|
| 4 |
|
|
| 122 |
|
Other Countries |
|
| (10 | ) |
|
| 55 |
|
|
| 11 |
|
|
| 70 |
|
Total Deferred Tax Expense (Recovery) |
|
| 6 |
|
|
| 227 |
|
|
| 6 |
|
|
| 283 |
|
Income Tax Expense (Recovery) |
| $ | 6 |
|
| $ | 228 |
|
| $ | (55 | ) |
| $ | 227 |
|
Effective Tax Rate |
|
| 13.3 | % |
|
| 43.7 | % |
|
| 343.8 | % |
|
| 17.7 | % |
Encana’s interim income tax expense is determined using the estimated annual effective income tax rate applied to year-to-date net earnings before income tax plus the effect of legislative changes and amounts in respect of prior periods. The estimated annual effective income tax rate is impacted by expected annual earnings, income tax related to foreign operations, the effect of legislative changes including U.S. Tax Reform, non-taxable capital gains and losses, tax differences on divestitures and transactions, and partnership tax allocations in excess of funding.
During the nine months ended September 30, 2018, the current income tax recovery was primarily due to the resolution of certain tax items relating to prior taxation years. During the nine months ended September 30, 2017, the current income tax recovery was primarily due to the successful resolution of certain tax items previously assessed by the taxing authorities relating to prior taxation years. During the three months ended September 30, 2018, the deferred tax expense was primarily due to the changes in the estimated annual effective income tax rate. During the three months ended September 30, 2017, the deferred tax expense was primarily due to the changes in the estimated annual effective income tax rate arising from gains recognized on foreign exchange and divestitures, including allocated goodwill.
The effective tax rate of 343.8 percent for the nine months ended September 30, 2018 is higher than the Canadian statutory rate of 27 percent primarily due to the current year items discussed above. The effective tax rate of 17.7 percent for the nine months ended September 30, 2017 is lower than the Canadian statutory rate of 27 percent primarily due to the items discussed above.
During the nine months ended September 30, 2018, there was no change to the provisional tax adjustment recognized in 2017 resulting from the re-measurement of the Company’s tax position due to a reduction of the U.S. federal corporate tax rate under U.S. Tax Reform. The provisional amount recognized may change due to additional regulatory guidance that may be issued, and from additional analysis or changes in interpretation and assumptions of the U.S. Tax Reform made by the Company.
19 |
| Three Months Ended |
|
| Nine Months Ended |
| |||||||||||||||||||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, |
| September 30, |
|
| September 30, |
| |||||||||||||||||||||||||
2017 | 2016 | �� | 2017 | 2016 |
| 2018 |
|
| 2017 |
|
| 2018 |
|
| 2017 |
| ||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||
Acquisitions |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||
Canadian Operations | $ | - | $ | 1 | $ | 31 | $ | 1 |
| $ | 15 |
|
| $ | - |
|
| $ | 17 |
|
| $ | 31 |
| ||||||||
USA Operations | 2 | 66 | 19 | 68 |
|
| - |
|
|
| 2 |
|
|
| - |
|
|
| 19 |
| ||||||||||||
Total Acquisitions | 2 | 67 | 50 | 69 |
|
| 15 |
|
|
| 2 |
|
|
| 17 |
|
|
| 50 |
| ||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||
Divestitures |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||
Canadian Operations | (20) | (457) | (26) | (457) |
|
| 2 |
|
|
| (20 | ) |
|
| (55 | ) |
|
| (26 | ) | ||||||||||||
USA Operations | (605) | (650) | (684) | (656) |
|
| (26 | ) |
|
| (605 | ) |
|
| (34 | ) |
|
| (684 | ) | ||||||||||||
Total Divestitures | (625) | (1,107) | (710) | (1,113) |
|
| (24 | ) |
|
| (625 | ) |
|
| (89 | ) |
|
| (710 | ) | ||||||||||||
Net Acquisitions & (Divestitures) | $ | (623) | $ | (1,040) | $ | (660) | $ | (1,044) |
| $ | (9 | ) |
| $ | (623 | ) |
| $ | (72 | ) |
| $ | (660 | ) |
Acquisitions
For the nine months ended September 30, 2017,2018, acquisitions in the Canadian and USA Operations were $17 million (2017 - $31 millionmillion) and nil (2017 - $19 million,million), respectively, which primarily included land purchases with oil and liquids rich potential.
Divestitures
In the Canadian Operations, divestitures during the nine months ended September 30, 2018 were $55 million, which primarily included the sale of the Pipestone midstream assets located in Alberta. During the nine months ended September 30, 2017, divestitures in the Canadian Operations were $26 million, which primarily included the sale of certain properties that did not complement Encana’s existing portfolio of assets.
In the USA Operations, divestitures during the three and nine months ended September 30, 2016, acquisitions2018 were $26 million and $34 million, respectively, which primarily included the purchasesale of land and property in Eagle Ford with oil and liquids rich potential.
Divestitures
certain properties that did not complement Encana’s existing portfolio of assets. During the three months ended September 30, 2017, divestitures in the USA Operations comprised the sale of the Piceance natural gas assets in northwestern Colorado for proceeds of approximately $605 million, after closing and other adjustments. During the nine months ended September 30, 2017, divestitures in the USA Operations were $684 million, which primarily included the sale of the Piceance natural gas assets and the sale of the Tuscaloosa Marine Shale assets in Mississippi and Louisiana.
During the three and nine months ended September 30, 2016, divestitures in the USA Operations were $650 million and $656 million, respectively, which primarily included the sale of the DJ Basin assets located in northern Colorado for approximately $628 million, after closing and other adjustments.
During the three and nine months ended September 30, 2017, divestitures in the Canadian Operations were $20 million and $26 million, respectively, which primarily included the sale of certain properties that did not complement Encana’s existing portfolio of assets. For the three and nine months ended September 30, 2016, divestitures in the Canadian Operations were $457 million, which primarily included the sale of the Gordondale assets in Montney located in northwestern Alberta for approximately C$603 million ($458 million), after closing adjustments.
Amounts received from the Company’s divestiture transactions have been deducted from the respective Canadian and U.S. full cost pools, except for divestitures that result in a significant alteration between capitalized costs and proved reserves in a country cost centre. For divestitures that result in a gain or loss and constitute a business, goodwill is allocated to the divestiture. Accordingly, for the three and nine months ended September 30, 2017, Encana recognized a gain of approximately $406 million, before tax, on the sale of the Company’s Piceance assets in the U.S. cost centre and allocated goodwill of $216 million. For the three and nine months ended September 30, 2016, Encana recognized a gain of approximately $397 million, before tax, on the sale of the Company’s Gordondale assets in the Canadian cost centre and allocated goodwill of $32 million.
|
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
2017 | 2016 | 2017 | 2016 | |||||||||||||
Interest Expense on: | ||||||||||||||||
Debt | $ | 67 | $ | 72 | $ | 200 | $ | 229 | ||||||||
The Bow office building | 16 | 16 | 47 | 47 | ||||||||||||
Capital leases | 6 | 6 | 16 | 18 | ||||||||||||
Other | 12 | 5 | 5 | 15 | ||||||||||||
$ | 101 | $ | 99 | $ | 268 | $ | 309 | |||||||||
6. Foreign Exchange (Gain) Loss, Net |
| |||||||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
2017 | 2016 | 2017 | 2016 | |||||||||||||
Unrealized Foreign Exchange (Gain) Loss on: | ||||||||||||||||
Translation of U.S. dollar financing debt issued from Canada | $ | (187) | $ | 44 | $ | (265) | $ | (233) | ||||||||
Translation of U.S. dollar risk management contracts issued from Canada | (21) | (1) | (53) | 5 | ||||||||||||
Translation of intercompany notes | (10) | 4 | 1 | 5 | ||||||||||||
(218) | 47 | (317) | (223) | |||||||||||||
Foreign Exchange on Settlements of: | ||||||||||||||||
U.S. dollar financing debt issued from Canada | 3 | (1) | 10 | (73) | ||||||||||||
U.S. dollar risk management contracts issued from Canada | (9) | - | (8) | - | ||||||||||||
Intercompany notes | 15 | (3) | 17 | (16) | ||||||||||||
Other Monetary Revaluations | (1) | 6 | 4 | 5 | ||||||||||||
$ | (210) | $ | 49 | $ | (294) | $ | (307) |
The unrealized foreign exchange (gain) loss on translation of U.S. dollar financing debt issued from Canada for the nine months ended September 30, 2017 disclosed in the table above includes anout-of-period adjustment recorded during the three months ended June 30, 2017, in respect of unrealized losses on a foreign-denominated capital lease obligation since December 2013. The cumulative impact from December 31, 2013 to June 30, 2017 recognized within foreign exchange (gain) loss in the Company’s Condensed Consolidated Statement of Earnings for the nine months ended September 30, 2017 was $68 million, before tax ($47 million, after tax). Encana has determined that the adjustment is not material to the Condensed Consolidated Financial Statements for the period ended September 30, 2017 or any prior periods. Accordingly, comparative periods presented in the Condensed Consolidated Financial Statements have not been restated.
9. |
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
2017 | 2016 | 2017 | 2016 | |||||||||||||
Current Tax | ||||||||||||||||
Canada | $ | - | $ | (15) | $ | (62) | $ | (28) | ||||||||
United States | 1 | - | 2 | - | ||||||||||||
Other Countries | - | 1 | 4 | 5 | ||||||||||||
Total Current Tax Expense (Recovery) | 1 | (14) | (56) | (23) | ||||||||||||
Deferred Tax | ||||||||||||||||
Canada | 71 | 154 | 91 | (204) | ||||||||||||
United States | 101 | (98) | 122 | (706) | ||||||||||||
Other Countries | 55 | 20 | 70 | 227 | ||||||||||||
Total Deferred Tax Expense (Recovery) | 227 | 76 | 283 | (683) | ||||||||||||
Income Tax Expense (Recovery) | $ | 228 | $ | 62 | $ | 227 | $ | (706) | ||||||||
Effective Tax Rate | 43.7% | 16.4% | 17.7% | 51.6% |
Encana’s interim income tax expense is determined using an estimated annual effective income tax rate applied toyear-to-date net earnings before income tax plus the effect of legislative changes and amounts in respect of prior periods. The estimated annual effective income tax rate is impacted by expected annual earnings, income tax related to foreign operations,non-taxable capital gains and losses, tax differences on divestitures and transactions, and partnership tax allocations in excess of funding.
During the nine months ended September 30, 2017, the current income tax recovery was primarily due to the successful resolution of certain tax items previously assessed by the tax authorities relating to prior taxation years. During the three and nine months ended September 30, 2017, the deferred tax expense was primarily due to the changes in the estimated annual effective income tax rate arising from gains recognized on foreign exchange and divestitures, including allocated goodwill. During the nine months ended September 30, 2016, the deferred tax recovery was primarily due to the ceiling test impairments recognized in the Canadian and USA Operations as disclosed in Note 8.
These items noted above resulted in an effective tax rate of 17.7 percent for the nine months ended September 30, 2017, which is lower than the Canadian statutory rate of 27 percent. The effective tax rate for the nine months ended September 30, 2016 exceeded the Canadian statutory tax rate of 27 percent primarily due to the impact of the foreign jurisdictional tax rates relative to the Canadian statutory tax rate applied to jurisdictional earnings.
|
As at September 30, 2017 | As at December 31, 2016 |
| As at September 30, 2018 |
|
| As at December 31, 2017 |
| |||||||||||||||||||||||||||||||||||||||||
Accumulated | Accumulated |
|
|
|
|
| Accumulated |
|
|
|
|
|
|
|
|
|
| Accumulated |
|
|
|
|
| |||||||||||||||||||||||||
Cost | DD&A | Net | Cost | DD&A | Net |
| Cost |
|
| DD&A |
|
| Net |
|
| Cost |
|
| DD&A |
|
| Net |
| |||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||||
Canadian Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||||||||
Proved properties | $ | 14,466 | $ | (14,053 | ) | $ | 413 | $ | 13,159 | $ | (12,896 | ) | $ | 263 |
| $ | 14,685 |
|
| $ | (13,869 | ) |
| $ | 816 |
|
| $ | 14,555 |
|
| $ | (14,047 | ) |
| $ | 508 |
| ||||||||||
Unproved properties | 322 | - | 322 | 285 | - | 285 |
|
| 255 |
|
|
| - |
|
|
| 255 |
|
|
| 311 |
|
|
| - |
|
|
| 311 |
| ||||||||||||||||||
Other | 45 | - | 45 | 54 | - | 54 |
|
| 27 |
|
|
| - |
|
|
| 27 |
|
|
| 43 |
|
|
| - |
|
|
| 43 |
| ||||||||||||||||||
14,833 | (14,053 | ) | 780 | 13,498 | (12,896 | ) | 602 |
|
| 14,967 |
|
|
| (13,869 | ) |
|
| 1,098 |
|
|
| 14,909 |
|
|
| (14,047 | ) |
|
| 862 |
| |||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||||
USA Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||||||||
Proved properties | 25,059 | (23,079 | ) | 1,980 | 26,393 | (25,300 | ) | 1,093 |
|
| 27,116 |
|
|
| (23,869 | ) |
|
| 3,247 |
|
|
| 25,610 |
|
|
| (23,240 | ) |
|
| 2,370 |
| ||||||||||||||||
Unproved properties | 4,362 | - | 4,362 | 4,913 | - | 4,913 |
|
| 3,709 |
|
|
| - |
|
|
| 3,709 |
|
|
| 4,169 |
|
|
| - |
|
|
| 4,169 |
| ||||||||||||||||||
Other | 21 | - | 21 | 44 | - | 44 |
|
| 17 |
|
|
| - |
|
|
| 17 |
|
|
| 16 |
|
|
| - |
|
|
| 16 |
| ||||||||||||||||||
29,442 | (23,079 | ) | 6,363 | 31,350 | (25,300 | ) | 6,050 |
|
| 30,842 |
|
|
| (23,869 | ) |
|
| 6,973 |
|
|
| 29,795 |
|
|
| (23,240 | ) |
|
| 6,555 |
| |||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||||
Market Optimization | 7 | (5 | ) | 2 | 6 | (4 | ) | 2 |
|
| 7 |
|
|
| (6 | ) |
|
| 1 |
|
|
| 7 |
|
|
| (5 | ) |
|
| 2 |
| ||||||||||||||||
Corporate & Other | 2,302 | (753 | ) | 1,549 | 2,148 | (663 | ) | 1,485 |
|
| 2,236 |
|
|
| (775 | ) |
|
| 1,461 |
|
|
| 2,299 |
|
|
| (764 | ) |
|
| 1,535 |
| ||||||||||||||||
$ | 46,584 | $ | (37,890 | ) | $ | 8,694 | $ | 47,002 | $ | (38,863 | ) | $ | 8,139 |
| $ | 48,052 |
|
| $ | (38,519 | ) |
| $ | 9,533 |
|
| $ | 47,010 |
|
| $ | (38,056 | ) |
| $ | 8,954 |
|
Canadian and USA Operations property, plant and equipment include internal costs directly related to exploration, development and construction activities of $146$159 million, which have been capitalized during the nine months ended September 30, 2017 (20162018 (2017 - $119$146 million). Included in Corporate and Other are $63$58 million ($5863 million as ofat December 31, 2016)2017) of international property costs, which have been fully impaired.
For the three and nine months ended September 30, 2017, as well as for the three months ended September 30, 2016, the Company did not recognize any ceiling test impairments in the Canadian or U.S. cost centres. For the nine months ended September 30, 2016, the Company recognizedbefore-tax ceiling test impairments of $493 million in the Canadian cost centre and $903 million in the U.S. cost centre. The impairments recognized in 2016 are included with accumulated DD&A in the table above and resulted primarily from the decline in the12-month average trailing prices which reduced proved reserves volumes and values.
The12-month average trailing prices used in the ceiling test calculations were based on the benchmark prices presented below. The benchmark prices were adjusted for basis differentials to determine local reference prices, transportation costs and tariffs, heat content and quality.
Oil & NGLs | Natural Gas | |||||||||||||||
WTI | Edmonton Condensate (2) | Henry Hub | AECO | |||||||||||||
($/bbl) | (C$/bbl) | ($/MMBtu) | (C$/MMBtu) | |||||||||||||
12-Month Average Trailing Reserves Pricing(1) | ||||||||||||||||
September 30, 2017 | 49.81 | 65.30 | 3.01 | 2.64 | ||||||||||||
December 31, 2016 | 42.75 | 55.39 | 2.49 | 2.17 | ||||||||||||
September 30, 2016 | 41.68 | 54.07 | 2.28 | 2.05 |
Capital Lease Arrangements
The Company has several lease arrangements that are accounted for as capital leases including an office building and an offshore production platform.
As at September 30, 2017,2018, the total carrying value of assets under capital lease was $47$43 million ($5146 million as at December 31, 2016)2017), net of accumulated amortization of $685$673 million ($648684 million as at December 31, 2016)2017). Liabilities for the capital lease arrangements are included in other liabilities and provisions in the Condensed Consolidated Balance Sheet and are disclosed in Note 10.11.
Other Arrangement
As at September 30, 2017,2018, Corporate and Other property, plant and equipment and total assets include a carrying value of $1,267$1,200 million ($1,1941,255 million as at December 31, 2016)2017) related to The Bow office building, which is under a25-year lease agreement. The Bow asset is being depreciated over the60-year estimated life of the building. At the conclusion of the25-year 25‑year term, the remaining asset and corresponding liability are expected to be derecognized as disclosed in Note 10.11.
21 |
As at | As at | |||||||
September 30, | December 31, | |||||||
2017 | 2016 | |||||||
U.S. Dollar Denominated Debt | ||||||||
U.S. Unsecured Notes | ||||||||
6.50% due May 15, 2019 | $ | 500 | $ | 500 | ||||
3.90% due November 15, 2021 | 600 | 600 | ||||||
8.125% due September 15, 2030 | 300 | 300 | ||||||
7.20% due November 1, 2031 | 350 | 350 | ||||||
7.375% due November 1, 2031 | 500 | 500 | ||||||
6.50% due August 15, 2034 | 750 | 750 | ||||||
6.625% due August 15, 2037(1) | 462 | 462 | ||||||
6.50% due February 1, 2038(1) | 505 | 505 | ||||||
5.15% due November 15, 2041(1) | 244 | 244 | ||||||
Total Principal | 4,211 | 4,211 | ||||||
Increase in Value of Debt Acquired | 26 | 26 | ||||||
Unamortized Debt Discounts and Issuance Costs | (40) | (39) | ||||||
Current Portion of Long-Term Debt | - | - | ||||||
$ | 4,197 | $ | 4,198 |
|
| As at |
|
| As at |
| ||
|
| September 30, |
|
| December 31, |
| ||
|
| 2018 |
|
| 2017 |
| ||
|
|
|
|
|
|
|
|
|
U.S. Dollar Denominated Debt |
|
|
|
|
|
|
|
|
U.S. Unsecured Notes: |
|
|
|
|
|
|
|
|
6.50% due May 15, 2019 |
| $ | 500 |
|
| $ | 500 |
|
3.90% due November 15, 2021 |
|
| 600 |
|
|
| 600 |
|
8.125% due September 15, 2030 |
|
| 300 |
|
|
| 300 |
|
7.20% due November 1, 2031 |
|
| 350 |
|
|
| 350 |
|
7.375% due November 1, 2031 |
|
| 500 |
|
|
| 500 |
|
6.50% due August 15, 2034 |
|
| 750 |
|
|
| 750 |
|
6.625% due August 15, 2037 |
|
| 462 |
|
|
| 462 |
|
6.50% due February 1, 2038 |
|
| 505 |
|
|
| 505 |
|
5.15% due November 15, 2041 |
|
| 244 |
|
|
| 244 |
|
Total Principal |
|
| 4,211 |
|
|
| 4,211 |
|
|
|
|
|
|
|
|
|
|
Increase in Value of Debt Acquired |
|
| 24 |
|
|
| 26 |
|
Unamortized Debt Discounts and Issuance Costs |
|
| (37 | ) |
|
| (40 | ) |
Current Portion of Long-Term Debt |
|
| (500 | ) |
|
| - |
|
|
| $ | 3,698 |
|
| $ | 4,197 |
|
As at September 30, 2017,2018, total long-term debt had a carrying value of $4,198 million and a fair value of $4,766 million (as at December 31, 2017 - carrying value of $4,197 million and a fair value of $4,845 million (as at December 31, 2016 - carrying value of $4,198 million and a fair value of $4,553$5,042 million). The estimated fair value of long-term borrowings is categorized within Level 2 of the fair value hierarchy and has been determined based on market information of long-term debt with similar terms and maturity, or by discounting future payments of interest and principal at interest rates expected to be available to the Company at period end.
On March 16, 2016, Encana announced tender offers (collectively, the “Tender Offers”) for certain of the Company’s outstanding senior notes (collectively, the “Notes”). The Tender Offers were for an aggregate purchase price of $250 million, excluding accrued and unpaid interest. The consideration for each $1,000 principal amount of Notes validly tendered and accepted for purchase included an early tender premium of $30 per $1,000 principal amount of Notes accepted for purchase, provided the Notes were validly tendered at or prior to the early tender date of March 29, 2016. All Notes validly tendered and accepted for purchase also received accrued and unpaid interest up to the settlement date.
On March 30, 2016, Encana announced an increase in the aggregate purchase price of the Tender Offers to $400 million, excluding accrued and unpaid interest, and accepted for purchase: i) $156 million aggregate principal amount of 5.15 percent notes due 2041; ii) $295 million aggregate principal amount of 6.50 percent notes due 2038; and iii) $38 million aggregate principal amount of 6.625 percent notes due 2037. The Company paid an aggregate amount of $406 million, including accrued and unpaid interest of $6 million and an early tender premium of $14 million, for Notes accepted for purchase. The Company used cash on hand and borrowings under its revolving credit facility to fund the Tender Offers.
Encana also recognized a gain on the early debt retirement of $103 million, before tax, representing the difference between the carrying amount of the Notes accepted for purchase and the consideration paid. The gain on the early debt retirement net of the early tender premium totaled $89 million, which is included in other (gains) losses in the Condensed Consolidated Statement of Earnings.
11. |
|
As at | As at |
| As at |
|
| As at |
| |||||||||
September 30, | December 31, |
| September 30, |
|
| December 31, |
| |||||||||
2017 | 2016 |
| 2018 |
|
| 2017 |
| |||||||||
|
|
|
|
|
|
|
| |||||||||
The Bow Office Building | $ | 1,354 | $ | 1,266 |
| $ | 1,293 |
|
| $ | 1,344 |
| ||||
Capital Lease Obligations | 315 | 304 |
|
| 233 |
|
|
| 295 |
| ||||||
Unrecognized Tax Benefits | 203 | 193 |
|
| 172 |
|
|
| 202 |
| ||||||
Pensions and Other Post-Employment Benefits | 123 | 124 |
|
| 121 |
|
|
| 116 |
| ||||||
Long-Term Incentive Costs (See Note 16) | 129 | 120 |
|
| 67 |
|
|
| 175 |
| ||||||
Other Derivative Contracts (See Notes 18, 19) | 16 | 14 |
|
| 10 |
|
|
| 14 |
| ||||||
Other | 19 | 26 |
|
| 20 |
|
|
| 21 |
| ||||||
$ | 2,159 | $ | 2,047 |
| $ | 1,916 |
|
| $ | 2,167 |
|
22 |
As described in Note 8,9, Encana has recognized the accumulated costs for The Bow office building, which is under a25-year lease agreement. At the conclusion of the lease term, the remaining asset and corresponding liability are expected to be derecognized. Encana has also subleased approximately 50 percent of The Bow office space under the lease agreement. The total expected future principal and interest payments related to the25-year lease agreement and the total undiscounted future amounts expected to be recovered from the sublease are outlined below.
2017 | 2018 | 2019 | 2020 | 2021 | Thereafter | Total |
| 2018 |
|
| 2019 |
|
| 2020 |
|
| 2021 |
|
| 2022 |
|
| Thereafter |
|
| Total |
| |||||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||||||||
Expected Future Lease Payments | $ | 19 | $ | 77 | $ | 77 | $ | 78 | $ | 78 | $ | 1,380 | $ | 1,709 |
| $ | 18 |
|
| $ | 74 |
|
| $ | 75 |
|
| $ | 76 |
|
| $ | 76 |
|
| $ | 1,255 |
|
| $ | 1,574 |
| ||||||||||||||
Less: Amounts Representing Interest | 16 | 66 | 64 | 64 | 63 | 868 | 1,141 |
|
| 16 |
|
|
| 62 |
|
|
| 62 |
|
|
| 61 |
|
|
| 60 |
|
|
| 777 |
|
|
| 1,038 |
| |||||||||||||||||||||
Present Value of Expected Future |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||||||||||||
Lease Payments | $ | 3 | $ | 11 | $ | 13 | $ | 14 | $ | 15 | $ | 512 | $ | 568 |
| $ | 2 |
|
| $ | 12 |
|
| $ | 13 |
|
| $ | 15 |
|
| $ | 16 |
|
| $ | 478 |
|
| $ | 536 |
| ||||||||||||||
Sublease Recoveries (undiscounted) | $ | (10) | $ | (37 | ) | $ | (37 | ) | $ | (38 | ) | $ | (38 | ) | $ | (680 | ) | $ | (840 | ) |
| $ | (9 | ) |
| $ | (37 | ) |
| $ | (37 | ) |
| $ | (37 | ) |
| $ | (37 | ) |
| $ | (617 | ) |
| $ | (774 | ) |
Capital Lease Obligations
As described in Note 8,9, the Company has several lease arrangements that are accounted for as capital leases including an office building and the Deep Panuke offshore Production Field Centre (“PFC”). Variable interests related to the PFC are described in Note 14.15.
The total expected future lease payments related to the Company’s capital lease obligations are outlined below.
2017 | 2018 | 2019 | 2020 | 2021 | Thereafter | Total |
| 2018 |
|
| 2019 |
|
| 2020 |
|
| 2021 |
|
| 2022 |
|
| Thereafter |
|
| Total |
| |||||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||||||||
Expected Future Lease Payments | $ | 24 | $ | 99 | $ | 99 | $ | 99 | $ | 87 | $ | 46 | $ | 454 |
| $ | 25 |
|
| $ | 99 |
|
| $ | 99 |
|
| $ | 87 |
|
| $ | 8 |
|
| $ | 38 |
|
| $ | 356 |
| ||||||||||||||
Less: Amounts Representing Interest | 5 | 20 | 15 | 10 | 4 | 7 | 61 |
|
| 5 |
|
|
| 15 |
|
|
| 10 |
|
|
| 4 |
|
|
| 2 |
|
|
| 5 |
|
|
| 41 |
| |||||||||||||||||||||
Present Value of Expected Future Lease Payments | $ | 19 | $ | 79 | $ | 84 | $ | 89 | $ | 83 | $ | 39 | $ | 393 |
| $ | 20 |
|
| $ | 84 |
|
| $ | 89 |
|
| $ | 83 |
|
| $ | 6 |
|
| $ | 33 |
|
| $ | 315 |
|
12. |
|
As at | As at |
| As at |
|
| As at |
| |||||||
September 30, | December 31, |
| September 30, |
|
| December 31, |
| |||||||
2017 | 2016 |
| 2018 |
|
| 2017 |
| |||||||
|
|
|
|
|
|
|
| |||||||
Asset Retirement Obligation, Beginning of Year | $ | 687 | $ 814 |
| $ | 514 |
|
| $ | 687 |
| |||
Liabilities Incurred and Acquired | 9 | 18 |
|
| 13 |
|
|
| 11 |
| ||||
Liabilities Settled and Divested | (267) | (107) |
|
| (28 | ) |
|
| (333 | ) | ||||
Change in Estimated Future Cash Outflows | - | (99) |
|
| - |
|
|
| 88 |
| ||||
Accretion Expense | 30 | 51 |
|
| 24 |
|
|
| 37 |
| ||||
Foreign Currency Translation | 25 | 10 |
|
| (12 | ) |
|
| 24 |
| ||||
Asset Retirement Obligation, End of Period | $ | 484 | $ 687 |
| $ | 511 |
|
| $ | 514 |
| |||
|
|
|
|
|
|
|
| |||||||
Current Portion | $ | 55 | $ 33 |
| $ | 104 |
|
| $ | 44 |
| |||
Long-Term Portion | 429 | 654 |
|
| 407 |
|
|
| 470 |
| ||||
$ | 484 | $ 687 |
| $ | 511 |
|
| $ | 514 |
|
23 |
Authorized
The Company is authorized to issue an unlimited number of no par value common shares and Class A Preferred Shares limited to a number equal to not more than 20 percent of the issued and outstanding number of common shares at the time of issuance. No Class A Preferred Shares are outstanding.
Issued and Outstanding
As at September 30, 2017 | As at December 31, 2016 |
| As at September 30, 2018 |
|
| As at December 31, 2017 |
| |||||||||||||||||||||||||
Number (millions) | Amount | Number (millions) | Amount |
| Number (millions) |
|
| Amount |
|
| Number (millions) |
|
| Amount |
| |||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||
Common Shares Outstanding, Beginning of Year | 973.0 | $ | 4,756 | 849.8 | $ | 3,621 |
|
| 973.1 |
|
| $ | 4,757 |
|
|
| 973.0 |
|
| $ | 4,756 |
| ||||||||||
Common Shares Issued | - | - | 123.1 | 1,134 | ||||||||||||||||||||||||||||
Common Shares Purchased |
|
| (20.7 | ) |
|
| (102 | ) |
|
| - |
|
|
| - |
| ||||||||||||||||
Common Shares Issued Under Dividend Reinvestment Plan | 0.1 | 1 | 0.1 | 1 |
|
| - |
|
|
| - |
|
|
| 0.1 |
|
|
| 1 |
| ||||||||||||
Common Shares Outstanding, End of Period | 973.1 | $ | 4,757 | 973.0 | $ | 4,756 |
|
| 952.4 |
|
| $ | 4,655 |
|
|
| 973.1 |
|
| $ | 4,757 |
|
During the nine months ended September 30, 2017,2018, Encana issued 49,56740,057 common shares totaling $0.5 million under the Company’s dividend reinvestment plan (“DRIP”). During the twelve months ended December 31, 2016,2017, Encana issued 121,24958,480 common shares totaling $0.9$0.6 million under the DRIP.
On September 23, 2016, Encana completed a public offering (the “2016 Share Offering”) of 107,000,000 common shares of Encana at a price of $9.35 per common share for gross proceeds of approximately $1.0 billion. After deducting underwriters’ fees and costs of the 2016 Share Offering, the net cash proceeds received were approximately $981 million. Pursuant to the 2016 Share Offering, Encana also granted the underwriters an over-allotment option (the “Over-Allotment Option”) to purchase up to an additional 16,050,000 common shares at a price of $9.35 per common share. On October 4, 2016, the Over-Allotment Option was exercised in full for additional gross proceeds of approximately $150 million. For the year ended December 31, 2016, the aggregate gross proceeds from the 2016 Share Offering, including the Over-Allotment Option, were approximately $1.15 billion. After deducting underwriters’ fees and costs of the 2016 Share Offering, the net cash proceeds received were approximately $1.13 billion.
Dividends
During the three months ended September 30, 2017,2018, Encana paid dividends of $0.015 per common share totaling $15$14 million (2016(2017 - $0.015 per common share totaling $13$15 million). During the nine months ended September 30, 2017,2018, Encana paid dividends of $0.045 per common share totaling $44$43 million (2016(2017 - $0.045 per common share totaling $38$44 million).
For the three and nine months ended September 30, 2017,2018, the dividends paid included $0.2$0.1 million and $0.5 million, respectively, in common shares issued in lieu of cash dividends under the DRIP (for the three and nine months ended September 30, 20162017 - $0.2 million and $0.8$0.5 million, respectively).
On November 7, 2017,October 31, 2018, the Board of Directors declared a dividend of $0.015 per common share payable on December 29, 201731, 2018 to common shareholders of record as of December 15, 2017.14, 2018.
On February 26, 2018, the Company announced it received approval from the TSX to purchase, for cancellation, up to 35 million common shares pursuant to a NCIB over a 12-month period from February 28, 2018 to February 27, 2019. The Company has authorization from its Board to spend up to $400 million on the NCIB.
All purchases are made in accordance with the NCIB at prevailing market prices plus brokerage fees, with consideration allocated to share capital up to the average carrying amount of the shares, and any excess is allocated to retained earnings/accumulated deficit.
For the nine months ended September 30, 2018, the Company purchased approximately 20.7 million common shares for total consideration of approximately $250 million. Of the amount paid, $102 million was charged to share capital and $148 million was charged to accumulated deficit.
24 |
The following table presents the computation of net earnings (loss) per common share:
| Three Months Ended |
|
|
| Nine Months Ended |
| ||||||||||||||||||||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, |
|
| September 30, |
|
|
| September 30, |
| |||||||||||||||||||||||||
(US$ millions, except per share amounts) | 2017 | 2016 | 2017 | 2016 |
|
| 2018 |
|
| 2017 |
|
|
| 2018 |
|
| 2017 |
| ||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||
Net Earnings (Loss) | $ | 294 | $ | 317 | $ | 1,056 | $ | (663) |
|
| $ | 39 |
|
| $ | 294 |
|
|
| $ | 39 |
|
| $ | 1,056 |
| ||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||
Number of Common Shares: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||
Weighted average common shares outstanding - Basic | 973.1 | 858.3 | 973.1 | 852.7 |
|
|
| 955.1 |
|
|
| 973.1 |
|
|
|
| 962.2 |
|
|
| 973.1 |
| ||||||||||||
Effect of dilutive securities | - | - | - | - |
|
|
| - |
|
|
| - |
|
|
|
| - |
|
|
| - |
| ||||||||||||
Weighted average common shares outstanding - Diluted | 973.1 | 858.3 | 973.1 | 852.7 | ||||||||||||||||||||||||||||||
Weighted Average Common Shares Outstanding - Diluted |
|
|
| 955.1 |
|
|
| 973.1 |
|
|
|
| 962.2 |
|
|
| 973.1 |
| ||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||
Net Earnings (Loss) per Common Share |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||
Basic & Diluted | $ | 0.30 | $ | 0.37 | $ | 1.09 | $ | (0.78) |
|
| $ | 0.04 |
|
| $ | 0.30 |
|
|
| $ | 0.04 |
|
| $ | 1.09 |
|
Encana Stock Option Plan
Encana has share-based compensation plans that allow employees to purchase common shares of the Company. Option exercise prices are not less than the market value of the common shares on the date the options are granted. All options outstanding as at September 30, 20172018 have associated Tandem Stock Appreciation Rights (“TSARs”) attached. In lieu of exercising the option, the associated TSARs give the option holder the right to receive a cash payment equal to the excess of the market price of Encana’s common shares at the time of the exercise over the original grant price.
In addition, certain stock options granted are performance-based whereby vesting is also subject to Encana attaining prescribed performance relative to predetermined key measures. Historically, most holders of options with TSARs have elected to exercise their stock options as a Stock Appreciation Right (“SAR”) in exchange for a cash payment. As a result, outstanding TSARs are not considered potentially dilutive securities.
Encana Restricted Share Units (“RSUs”)
Encana has a share-based compensation plan whereby eligible employees and Directors are granted RSUs. An RSU is a conditional grant to receive the equivalent of an Encana common share or the cash equivalent, as determined by Encana, upon vesting of the RSUs and in accordance with the terms of the RSU Plan and Grant Agreement. The Company intends to settlecurrently settles vested RSUs in cash on the vesting date.cash. As a result, RSUs are not considered potentially dilutive securities.
14. |
|
| Three Months Ended |
|
| Nine Months Ended |
| |||||||||||||||||||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, |
| September 30, |
|
| September 30, |
| |||||||||||||||||||||||||
2017 | 2016 | 2017 | 2016 |
| 2018 |
|
| 2017 |
|
| 2018 |
|
| 2017 |
| |||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||
Foreign Currency Translation Adjustment |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||
Balance, Beginning of Period | $ | 1,125 | $ | 1,127 | $ | 1,200 | $ | 1,383 |
| $ | 1,028 |
|
| $ | 1,125 |
|
| $ | 1,029 |
|
| $ | 1,200 |
| ||||||||
Change in Foreign Currency Translation Adjustment | (97) | 36 | (172) | (220) |
|
| 22 |
|
|
| (97 | ) |
|
| 21 |
|
|
| (172 | ) | ||||||||||||
Balance, End of Period | $ | 1,028 | $ | 1,163 | $ | 1,028 | $ | 1,163 |
| $ | 1,050 |
|
| $ | 1,028 |
|
| $ | 1,050 |
|
| $ | 1,028 |
| ||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||
Pension and Other Post-Employment Benefit Plans |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||
Balance, Beginning of Period | $ | 9 | $ | 7 | $ | 10 | $ | 7 |
| $ | 12 |
|
| $ | 9 |
|
| $ | 13 |
|
| $ | 10 |
| ||||||||
Reclassification of Net Actuarial (Gains) and Losses to Net Earnings (See Note 17) | - | (1) | (1) | (1) |
|
| - |
|
|
| - |
|
|
| (1 | ) |
|
| (1 | ) | ||||||||||||
Income Taxes | - | - | - | - |
|
| - |
|
|
| - |
|
|
| - |
|
|
| - |
| ||||||||||||
Curtailment in Net Defined Periodic Benefit Cost (See Note 17) | (1) | - | (1) | - |
|
| - |
|
|
| (1 | ) |
|
| - |
|
|
| (1 | ) | ||||||||||||
Income Taxes | - | - | - | - |
|
| - |
|
|
| - |
|
|
| - |
|
|
| - |
| ||||||||||||
Balance, End of Period | $ | 8 | $ | 6 | $ | 8 | $ | 6 |
| $ | 12 |
|
| $ | 8 |
|
| $ | 12 |
|
| $ | 8 |
| ||||||||
Total Accumulated Other Comprehensive Income | $ | 1,036 | $ | 1,169 | $ | 1,036 | $ | 1,169 |
| $ | 1,062 |
|
| $ | 1,036 |
|
| $ | 1,062 |
|
| $ | 1,036 |
|
25 |
Production Field Centre
In 2008, Encana entered into a contract for the design, construction and operation of the PFC at its Deep Panuke facility. Upon commencement of operations in December 2013, Encana recognized the PFC as a capital lease asset. Under the lease contract, Encana has a purchase option and the option to extend the lease for 12one-year terms at fixed prices after the initial lease term expires in 2021.
As a result of the purchase option and fixed price renewal options, Encana has determined it holds variable interests and that the related leasing entity qualifies as a variable interest entity (“VIE”). Encana is not the primary beneficiary of the VIE as the Company does not have the power to direct the activities that most significantly impact the VIE’s economic performance. Encana is not required to provide any financial support or guarantees to the leasing entity or its affiliates, other than the contractual payments under the lease and operating agreements. Encana’s maximum exposure is the expected lease payments over the initial contract term. As at September 30, 2017,2018, Encana had a capital lease obligation of $332$259 million ($299314 million as at December 31, 2016)2017) related to the PFC.
Veresen Midstream Limited Partnership
Veresen Midstream Limited Partnership (“VMLP”) provides gathering, compression and processing services under various agreements related to the Company’s development of liquids and natural gas production in the Montney play. As at September 30, 2017,2018, VMLP provides approximately 6301,240 MMcf/d of natural gas gathering and compression and 652977 MMcf/d of natural gas processing under long-term service agreements with remaining terms ranging from up to 1513 to 2827 years and have various renewal terms providing up to a potential maximum of 10 years.
Encana has determined that VMLP is a VIE and that Encana holds variable interests in VMLP. Encana is not the primary beneficiary as the Company does not have the power to direct the activities that most significantly impact VMLP’s economic performance. These key activities relate to the construction, operation, maintenance and marketing of the assets owned by VMLP. The variable interests arise from certain terms under the various long-term service agreements and include: i) a take or pay for volumes in certain agreements; ii) an operating fee of which a portion can be converted into a fixed fee once VMLP assumes operatorship of certain assets; and iii) a potential payout of minimum costs in certain agreements. The potential payout of minimum costs will be assessed in the eighth year of the assets’ service period and is based on whether there is an overall shortfall of total system cash flows from natural gas gathered and compressed under certain agreements. The potential payout amount can be reduced in the event VMLP markets unutilized capacity to third party users. Encana is not required to provide any financial support or guarantees to VMLP.
As a result of Encana’s involvement with VMLP, the maximum total exposure, which represents the potential exposure to Encana in the event the assets under the agreements are deemed worthless, is estimated to be $2,245$2,425 million as at September 30, 2017.2018. The estimate comprises the take or pay volume commitments and the potential payout of minimum costs. The take or pay volume commitments associated with certain gathering and processing assets are included in Note 21 under Transportation and Processing. The potential payout requirement is highly uncertain as the amount is contingent on future production estimates, pace of development and the amount of capacity contracted to third parties. As at September 30, 2017,2018, there were no accounts payable and accrued liabilities outstanding related to the take or pay commitment.
16. |
|
In February 2016, Encana announced workforce reductions to better align staffing levels and the organizational structure with the Company’s reduced capital spending program. During 2016, Encana incurred total restructuring charges of $34 million, before tax, primarily related to severance costs. As at September 30, 2017, all restructuring costs have been paid.
Restructuring charges are included in administrative expense presented in the Corporate & Other segment in the Condensed Consolidated Statement of Earnings.
As at September 30, 2017 | As at December 31, 2016 | |||||||
Outstanding Restructuring Accrual, Beginning of Year | $ | 7 | $ | 13 | ||||
Current Period Restructuring Expenses Incurred | - | 34 | ||||||
Restructuring Costs Paid | (7) | (40) | ||||||
Outstanding Restructuring Accrual, End of Period | $ | - | $ | 7 |
|
Encana has a number of compensation arrangements under which the Company awards various types of long-term incentive grants to eligible employees.employees and Directors. They may include TSARs, Performance TSARs, SARs, Performance Share Units (“PSUs”), Deferred Share Units (“DSUs”) and RSUs. These compensation arrangements are share-based.
Encana accounts for TSARs, Performance TSARs, SARs, PSUs and RSUs held by employees as cash-settled share-based payment transactions and, accordingly, accrues compensation costs over the vesting period based on the fair value of the rights determined using the Black-Scholes-Merton and other fair value models.
26 |
The following weighted average assumptions were used to determine the fair value of the share units held by employees:outstanding:
As at September 30, 2017 | As at September 30, 2016 |
| As at September 30, 2018 |
|
| As at September 30, 2017 |
| |||||||||||||||||||
US$ Share Units | C$ Share Units | US$ Share Units | C$ Share Units |
| US$ Share Units |
| C$ Share Units |
|
| US$ Share Units |
| C$ Share Units |
| |||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||||||||
Risk Free Interest Rate | 1.53% | 1.53% | 0.49% | 0.49% |
| 2.18% |
| 2.18% |
|
| 1.53% |
| 1.53% |
| ||||||||||||
Dividend Yield | 0.51% | 0.53% | 0.57% | 0.58% |
| 0.46% |
| 0.46% |
|
| 0.51% |
| 0.53% |
| ||||||||||||
Expected Volatility Rate(1) | 59.35% | 55.21% | 56.11% | 52.27% |
| 55.44% |
| 51.90% |
|
| 59.35% |
| 55.21% |
| ||||||||||||
Expected Term | 1.6 yrs | 1.7 yrs | 1.6 yrs | 1.8 yrs |
| 1.6 yrs |
| 2.0 yrs |
|
| 1.6 yrs |
| 1.7 yrs |
| ||||||||||||
Market Share Price | US$11.78 | C$14.69 | US$10.47 | C$13.71 |
| US$13.11 |
| C$16.93 |
|
| US$11.78 |
| C$14.69 |
|
(1) | Volatility was estimated using historical rates. |
The Company has recognized the following share-based compensation costs:
Three Months Ended September 30, | Nine Months Ended September 30, |
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
| |||||||||||||||||||||||||
2017 | 2016 | 2017 | 2016 |
| 2018 |
|
| 2017 |
|
| 2018 |
|
| 2017 |
| |||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||
Total Compensation Costs of Transactions Classified as Cash-Settled | $ 91 | $ 68 | $ 84 | $ 114 |
| $ | 36 |
|
| $ | 91 |
|
| $ | 118 |
|
| $ | 84 |
| ||||||||||||
Less: Total Share-Based Compensation Costs Capitalized | (30) | (15) | (30) | (25) |
|
| (11 | ) |
|
| (30 | ) |
|
| (33 | ) |
|
| (30 | ) | ||||||||||||
Total Share-Based Compensation Expense (Recovery) | $ 61 | $ 53 | $ 54 | $ 89 |
| $ | 25 |
|
| $ | 61 |
|
| $ | 85 |
|
| $ | 54 |
| ||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||
Recognized on the Condensed Consolidated Statement of Earnings in: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||
Operating | $ 18 | $ 18 | $ 18 | $ 31 |
| $ | 8 |
|
| $ | 18 |
|
| $ | 24 |
|
| $ | 18 |
| ||||||||||||
Administrative | 43 | 35 | 36 | 58 |
|
| 17 |
|
|
| 43 |
|
|
| 61 |
|
|
| 36 |
| ||||||||||||
$ 61 | $ 53 | $ 54 | $ 89 |
| $ | 25 |
|
| $ | 61 |
|
| $ | 85 |
|
| $ | 54 |
|
As at September 30, 2017,2018, the liability for share-based payment transactions totaled $247$357 million ($208327 million as at December 31, 2016)2017), of which $118$290 million ($88152 million as at December 31, 2016)2017) is recognized in accounts payable and accrued liabilities and $129$67 million ($120175 million as at December 31, 2016)2017) is recognized in other liabilities and provisions in the Condensed Consolidated Balance Sheet.
As at September 30, 2017 | As at December 31, 2016 |
|
|
|
| As at September 30, 2018 |
| As at December 31, 2017 |
| |||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||||||
Liability for Cash-Settled Share-Based Payment Transactions: |
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Unvested | $ | 204 | $ | 171 |
|
|
|
|
| $ | 287 |
|
| $ | 274 |
| ||||
Vested | 43 | 37 |
|
|
|
|
|
| 70 |
|
|
| 53 |
| ||||||
$ | 247 | $ | 208 |
|
|
|
|
| $ | 357 |
|
| $ | 327 |
|
The following units were granted primarily in conjunction with the Company’s February annual long-term incentive award. The TSARs, SARs, PSUs and SARsRSUs were granted at the volume-weighted average trading price of Encana’s common shares for the five days prior to the grant date.
Nine Months Ended September 30, | ||||
TSARs | 872 | |||
SARs | 377 | |||
PSUs | 2,546 | |||
DSUs | 45 | |||
RSUs | 5,358 |
27 |
The Company has recognized total benefit plans expense which includes pension benefits and other post-employment benefits (“OPEB”) for the nine months ended September 30 as follows:
Pension Benefits | OPEB | Total |
| Pension Benefits |
|
| OPEB |
|
| Total |
| |||||||||||||||||||||||||||||||||||||
2017 | 2016 | 2017 | 2016 | 2017 | 2016 |
| 2018 |
|
| 2017 |
|
| 2018 |
|
| 2017 |
|
| 2018 |
|
| 2017 |
| |||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||||
Net Defined Periodic Benefit Cost | $ | - | $ | (1) | $ | 1 | $ | 10 | $ | 1 | $ | 9 |
| $ | 1 |
|
| $ | - |
|
| $ | 5 |
|
| $ | 1 |
|
| $ | 6 |
|
| $ | 1 |
| ||||||||||||
Defined Contribution Plan Expense | 17 | 21 | - | - | 17 | 21 |
|
| 17 |
|
|
| 17 |
|
|
| - |
|
|
| - |
|
|
| 17 |
|
|
| 17 |
| ||||||||||||||||||
Total Benefit Plans Expense | $ | 17 | $ | 20 | $ | 1 | $ | 10 | $ | 18 | $ | 30 |
| $ | 18 |
|
| $ | 17 |
|
| $ | 5 |
|
| $ | 1 |
|
| $ | 23 |
|
| $ | 18 |
|
Of the total benefit plans expense, $18$17 million (2016(2017 - $23$18 million) was included in operating expense, $6 million (2016(2017 - $7$6 million) was included in administrative expense and a gain of nil (2017 - $6 million (2016 - nil)million) was included in other (gains) losses, net.
The net defined periodic benefit cost for the nine months ended September 30 is as follows:
Defined Benefits | OPEB | Total |
| Defined Benefits |
|
| OPEB |
|
| Total |
| |||||||||||||||||||||||||||||||||||||
2017 | 2016 | 2017 | 2016 | 2017 | 2016 |
| 2018 |
|
| 2017 |
|
| 2018 |
|
| 2017 |
|
| 2018 |
|
| 2017 |
| |||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||||
Service Cost | $ | 1 | $ | 1 | $ | 6 | $ | 8 | $ | 7 | $ | 9 |
| $ | 1 |
|
| $ | 1 |
|
| $ | 5 |
|
| $ | 6 |
|
| $ | 6 |
|
| $ | 7 |
| ||||||||||||
Interest Cost | 6 | 6 | 2 | 3 | 8 | 9 |
|
| 5 |
|
|
| 6 |
|
|
| 2 |
|
|
| 2 |
|
|
| 7 |
|
|
| 8 |
| ||||||||||||||||||
Expected Return on Plan Assets | (7) | (8) | - | - | (7) | (8) |
|
| (6 | ) |
|
| (7 | ) |
|
| - |
|
|
| - |
|
|
| (6 | ) |
|
| (7 | ) | ||||||||||||||||||
Amounts Reclassified from Accumulated Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||||||||
Amortization of net actuarial (gains) and losses | - | - | (1) | (1) | (1) | (1) |
|
| 1 |
|
|
| - |
|
|
| (2 | ) |
|
| (1 | ) |
|
| (1 | ) |
|
| (1 | ) | ||||||||||||||||||
Curtailment | - | - | (1) | - | (1) | - |
|
| - |
|
|
| - |
|
|
| - |
|
|
| (1 | ) |
|
| - |
|
|
| (1 | ) | ||||||||||||||||||
Curtailment | - | - | (5) | - | (5) | - |
|
| - |
|
|
| - |
|
|
| - |
|
|
| (5 | ) |
|
| - |
|
|
| (5 | ) | ||||||||||||||||||
Total Net Defined Periodic Benefit Cost | $ | - | $ | (1) | $ | 1 | $ | 10 | $ | 1 | $ | 9 | ||||||||||||||||||||||||||||||||||||
Total Net Defined Periodic Benefit Cost (1) |
| $ | 1 |
|
| $ | - |
|
| $ | 5 |
|
| $ | 1 |
|
| $ | 6 |
|
| $ | 1 |
|
(1) | The components of total net defined periodic benefit cost, excluding the service cost component, are included in other (gains) losses, net. |
18. | Fair Value Measurements |
The fair values of cash and cash equivalents, accounts receivable and accrued revenues, and accounts payable and accrued liabilities approximate their carrying amounts due to the short-term maturity of those instruments.
Recurring fair value measurements are performed for risk management assets and liabilities and other derivative contracts, as discussed further in Note 19. These items are carried at fair value in the Condensed Consolidated Balance Sheet and are classified within the three levels of the fair value hierarchy in the following tables. There have been no significant transfers between the hierarchy levels during the period.
28 |
Fair value changes and settlements for amounts related to risk management assets and liabilities are recognized in revenues, transportation and processing expense, and foreign exchange gains and losses according to their purpose.
As at September 30, 2017 | Level 1 Quoted Prices in Active Markets | Level 2 Other | Level 3 Significant Unobservable Inputs | Total Fair Value | Netting (1) | Carrying Amount | ||||||||||||||||||||||||||||||||||||||||||
As at September 30, 2018 |
| Level 1 Quoted Prices in Active Markets |
|
| Level 2 Other Observable Inputs |
|
| Level 3 Significant Unobservable Inputs |
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| Total Fair Value |
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| Netting (1) |
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| Carrying Amount |
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Risk Management Assets |
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Commodity Derivatives: |
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Current assets | $ | - | $ | 133 | $ | - | $ | 133 | $ | (57) | $ | 76 |
| $ | 13 |
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| $ | 200 |
|
| $ | - |
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| $ | 213 |
|
| $ | (77 | ) |
| $ | 136 |
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Long-term assets | - | 90 | - | 90 | (14) | 76 |
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| - |
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| 144 |
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| - |
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| 144 |
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| (14 | ) |
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| 130 |
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Foreign Currency Derivatives: |
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Current assets | - | 31 | - | 31 | - | 31 |
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| - |
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| 10 |
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| - |
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| 10 |
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| - |
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| 10 |
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Long-term assets | - | 8 | - | 8 | - | 8 |
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| - |
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| 2 |
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| - |
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| 2 |
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| - |
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| 2 |
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Risk Management Liabilities |
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Commodity Derivatives: |
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Current liabilities | $ | 10 | $ | 59 | $ | 5 | $ | 74 | $ | (57) | $ | 17 |
| $ | - |
|
| $ | 405 |
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| $ | 122 |
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| $ | 527 |
|
| $ | (77 | ) |
| $ | 450 |
| ||||||||||||
Long-term liabilities | 1 | 22 | 2 | 25 | (14) | 11 |
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| - |
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| 56 |
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| 26 |
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| 82 |
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| (14 | ) |
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| 68 |
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Other Derivative Contracts | ||||||||||||||||||||||||||||||||||||||||||||||||
Current in accounts payable and accrued liabilities | $ | - | $ | 5 | $ | - | $ | 5 | $ | - | $ | 5 | ||||||||||||||||||||||||||||||||||||
Long-term in other liabilities and provisions | - | 16 | - | 16 | - | 16 | ||||||||||||||||||||||||||||||||||||||||||
As at December 31, 2016 | Level 1 Quoted Prices in Active Markets | Level 2 Other | Level 3 Significant Unobservable Inputs | Total Fair Value | Netting (1) | Carrying Amount | ||||||||||||||||||||||||||||||||||||||||||
Risk Management Assets | ||||||||||||||||||||||||||||||||||||||||||||||||
Commodity Derivatives: | ||||||||||||||||||||||||||||||||||||||||||||||||
Current assets | $ | - | $ | 11 | $ | - | $ | 11 | $ | (11) | $ | - | ||||||||||||||||||||||||||||||||||||
Long-term assets | - | 19 | - | 19 | (3) | 16 | ||||||||||||||||||||||||||||||||||||||||||
Risk Management Liabilities | ||||||||||||||||||||||||||||||||||||||||||||||||
Commodity Derivatives: | ||||||||||||||||||||||||||||||||||||||||||||||||
Current liabilities | $ | - | $ | 228 | $ | 36 | $ | 264 | $ | (11) | $ | 253 | ||||||||||||||||||||||||||||||||||||
Long-term liabilities | - | 38 | - | 38 | (3) | 35 | ||||||||||||||||||||||||||||||||||||||||||
Foreign Currency Derivatives: |
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Current liabilities | - | 1 | - | 1 | - | 1 |
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| - |
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| - |
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| - |
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| - |
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| - |
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| - |
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Other Derivative Contracts |
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Current in accounts payable and accrued liabilities | $ | - | $ | 5 | $ | - | $ | 5 | $ | - | $ | 5 |
| $ | - |
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| $ | 5 |
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| $ | - |
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| $ | 5 |
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| $ | - |
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| $ | 5 |
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Long-term in other liabilities and provisions | - | 14 | - | 14 | - | 14 |
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| - |
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| 10 |
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| - |
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| 10 |
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| - |
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| 10 |
|
As at December 31, 2017 |
| Level 1 Quoted Prices in Active Markets |
|
| Level 2 Other Observable Inputs |
|
| Level 3 Significant Unobservable Inputs |
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| Total Fair Value |
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| Netting (1) |
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| Carrying Amount |
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Risk Management Assets |
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Commodity Derivatives: |
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Current assets |
| $ | - |
|
| $ | 189 |
|
| $ | - |
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| $ | 189 |
|
| $ | (15 | ) |
| $ | 174 |
|
Long-term assets |
|
| - |
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|
| 248 |
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| - |
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| 248 |
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| (2 | ) |
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| 246 |
|
Foreign Currency Derivatives: |
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Current assets |
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| - |
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| 31 |
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| - |
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| 31 |
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| - |
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| 31 |
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Risk Management Liabilities |
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Commodity Derivatives: |
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Current liabilities |
| $ | 3 |
|
| $ | 196 |
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| $ | 51 |
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| $ | 250 |
|
| $ | (15 | ) |
| $ | 235 |
|
Long-term liabilities |
|
| - |
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| 15 |
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| - |
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| 15 |
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| (2 | ) |
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| 13 |
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Foreign Currency Derivatives: |
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Current liabilities |
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| - |
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| 1 |
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| - |
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| 1 |
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| - |
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| 1 |
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Other Derivative Contracts |
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Current in accounts payable and accrued liabilities |
| $ | - |
|
| $ | 5 |
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| $ | - |
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| $ | 5 |
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| $ | - |
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| $ | 5 |
|
Long-term in other liabilities and provisions |
|
| - |
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| 14 |
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| - |
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| 14 |
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| - |
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| 14 |
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(1) | Netting to offset derivative assets and liabilities where the legal right and intention to offset exists, or where counterparty master netting arrangements contain provisions for net settlement. |
The Company’s Level 1 and Level 2 risk management assets and liabilities consist of commodity fixed price contracts, NYMEXthree-way options, NYMEX costless collars,fixed price swaptions, NYMEX call options, foreign currency swaps and basis swaps with terms to 2023. Level 2 also includes financial guarantee contracts as discussed in Note 19. The fair values of these contracts are based on a market approach and are estimated using inputs which are either directly or indirectly observable at the reporting date, such as exchange and other published prices, broker quotes and observable trading activity.
29 |
Level 3 Fair Value Measurements
As at September 30, 2017,2018, the Company’s Level 3 risk management assets and liabilities consist of WTIthree-way options and WTI costless collars with terms to 2018.2019. The WTIthree-way options are a combination of a sold call, bought put and a sold put. The WTI costless collars are a combination of a sold call and a bought put. These contracts allow the Company to participate in the upside of commodity prices to the ceiling of the call option and provide the Company with complete (collars)
or partial(three-way) downside price protection through the put options. The fair values of the WTIthree-way options and WTI costless collars are based on the income approach and are modelled using observable and unobservable inputs such as implied volatility. The unobservable inputs are obtained from third parties whenever possible and reviewed by the Company for reasonableness.
A summary of changes in Level 3 fair value measurements for the nine months ended September 30 is presented below:
Risk Management |
| Risk Management |
| |||||||||||||
2017 |
2016 |
| 2018 |
|
| 2017 |
| |||||||||
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| |||||||||
Balance, Beginning of Year
| $ | (36) | $ | 16 |
| $ | (51 | ) |
| $ | (36 | ) | ||||
Total Gains (Losses)
| 20 | 4 |
|
| (177 | ) |
|
| 38 |
| ||||||
Purchases, Sales, Issuances and Settlements: |
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|
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| ||||||||
Purchases, sales and issuances |
|
| - |
|
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| - |
| ||||||||
Settlements
| 9 | (18) |
|
| 80 |
|
|
| (9 | ) | ||||||
Transfers Out of Level 3(1)
| - | (10) |
|
| - |
|
|
| - |
| ||||||
Balance, End of Period
| $ | (7) | $ | (8) |
| $ | (148 | ) |
| $ | (7 | ) | ||||
Change in Unrealized Gains (Losses) Related to Assets and Liabilities Held at End of Period | $ | 8 | $ | (6) |
| $ | (136 | ) |
| $ | 8 |
|
(1) | The Company’s policy is to recognize transfers out of Level 3 on the date of the event of change in circumstances that caused the transfer. |
Quantitative information about unobservable inputs used in Level 3 fair value measurements is presented below:
| Valuation Technique | Unobservable Input | As at September 30, 2018 | As at December 31, 2017 | ||||||||||||||
Risk Management - WTI Options | Option Model | Implied Volatility | 23% - 102% | 17% - |
A 10 percent increase or decrease in implied volatility for the WTI options would cause a corresponding $1$7 million ($32 million as at December 31, 2016)2017) increase or decrease to net risk management assets and liabilities.
30 |
A) Financial Instruments
Encana’s financial assets and liabilities are recognized in cash and cash equivalents, accounts receivable and accrued revenues, accounts payable and accrued liabilities, risk management assets and liabilities, long-term debt and other liabilities and provisions and long-term debt.provisions.
B) Risk Management Activities
Encana uses derivative financial instruments to manage its exposure to cash flow variability from commodity prices electricity costs and fluctuating foreign currency exchange rates. The Company does not apply hedge accounting to any of its derivative financial instruments. As a result, gains and losses from changes in the fair value are recognized in net earnings.
Commodity Price Risk
Commodity price risk arises from the effect that fluctuations in future commodity prices may have on future cash flows. To partially mitigate exposure to commodity price risk, the Company has entered into various derivative financial instruments. The use of these derivative instruments is governed under formal policies and is subject to limits established by the Board of Directors. The Company’s policy is to not use derivative financial instruments for speculative purposes.
Crude Oil and NGLs - To partially mitigate crude oil and NGL commodity price risk, the Company usesWTI-based and Mont Belvieu-based contracts such as fixed price contracts, fixed price swaptions, options and costless collars. Encana has also entersentered into basis swaps to manage against widening price differentials between various production areas and benchmark price points.
Natural Gas - To partially mitigate natural gas commodity price risk, the Company uses NYMEX-based contracts such as fixed price contracts, optionsfixed price swaptions and costless collars.options. Encana has also entersentered into basis swaps to manage against widening price differentials between various production areas and benchmark price points.
Power - The Company has entered into Canadian dollar denominated derivative contracts to manage its electricity consumption costs.
Foreign Exchange Risk
Foreign exchange risk arises from changes in foreign currency exchange rates that may affect the fair value or future cash flows of the Company’s financial assets or liabilities. To partially mitigate the effect of foreign exchange fluctuations on future commodity revenues and expenses, the Company may enter into foreign currency derivative contracts. As at September 30, 2017,2018, Encana had $135has entered into $179 million notional U.S. dollar denominated currency swaps at an average exchange rate of US$0.75030.7606 to C$1, maturingwhich mature monthly through the remainder of 20172018 and $350 million notional U.S. dollar denominated currency swaps at an average exchange rate of US$0.73590.7579 to C$1, maturingwhich mature monthly through 2018.
31 |
Risk Management Positions as at September 30, 20172018
Notional Volumes | Term | Average Price | Fair Value |
| Notional Volumes |
| Term |
| Average Price |
|
| Fair Value |
| |||||||||||
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Crude Oil and NGL Contracts | US$/bbl |
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| US$/bbl |
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Fixed Price Contracts |
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WTI Fixed Price | 33.0 Mbbls/d | 2017 | 52.27 | $ | 1 |
| 110.5 Mbbls/d |
| 2018 |
|
| 55.65 |
|
| $ | (175 | ) | |||||||
WTI Fixed Price | 59.2 Mbbls/d | 2018 | 52.95 | 24 |
| 35.0 Mbbls/d |
| 2019 |
|
| 60.31 |
|
|
| (134 | ) | ||||||||
Propane Fixed Price |
| 9.0 Mbbls/d |
| 2018 |
|
| 39.05 |
|
|
| (5 | ) | ||||||||||||
Propane Fixed Price |
| 4.8 Mbbls/d |
| 2019 |
|
| 34.87 |
|
|
| (9 | ) | ||||||||||||
Butane Fixed Price | 2.5 Mbbls/d | 2017 | 36.12 | (2 | ) |
| 7.0 Mbbls/d |
| 2018 |
|
| 43.49 |
|
|
| (7 | ) | |||||||
Butane Fixed Price |
| 3.0 Mbbls/d |
| 2019 |
|
| 38.89 |
|
|
| (8 | ) | ||||||||||||
Ethane Fixed Price |
| 3.0 Mbbls/d |
| 2019 |
|
| 17.19 |
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| (1 | ) | ||||||||||||
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WTI Fixed Price Swaptions (1) |
| 24.0 Mbbls/d |
| Q1 - Q2 2019 |
|
| 63.13 |
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| (42 | ) | ||||||||||||
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WTI Three-Way Options |
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Sold call / bought put / sold put | 25.0 Mbbls/d | 2017 | 61.40 / 49.95 / 39.40 | 2 |
| 16.0 Mbbls/d |
| 2018 |
| 54.49 / 47.17 / 36.88 |
|
|
| (25 | ) | |||||||||
WTI Three-Way Options | ||||||||||||||||||||||||
Sold call / bought put / sold put | 10.0 Mbbls/d | 2018 | 54.19 / 45.00 / 35.00 | (7 | ) |
| 52.5 Mbbls/d |
| 2019 |
| 69.22 / 59.47 / 48.57 |
|
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| (110 | ) | ||||||||
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WTI Costless Collars |
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Sold call / bought put | 30.0 Mbbls/d | 2017 | 56.05 / 46.22 | (1 | ) |
| 10.0 Mbbls/d |
| 2018 |
| 57.08 / 45.00 |
|
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| (13 | ) | ||||||||
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WTI Costless Collars | ||||||||||||||||||||||||
Sold call / bought put | 10.0 Mbbls/d | 2018 | 57.08 / 45.00 | (1 | ) | |||||||||||||||||||
Basis Contracts (2) |
|
|
| 2018 |
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| 15 |
| ||||||||||||
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|
| 2019 |
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| 27 |
| |||||||||||||
Basis Contracts(1) | 2017 - 2020
|
| (20
| )
| ||||||||||||||||||||
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| 2020 |
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| (4 | ) | ||||||||||||
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Crude Oil and NGLs Fair Value Position | (4 | ) |
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| (491 | ) | ||||||||||
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Natural Gas Contracts | US$/Mcf |
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| US$/Mcf |
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| ||||||||||||
Fixed Price Contracts |
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NYMEX Fixed Price | 405 MMcf/d | 2017 | 3.13 | 3 |
| 1,017 MMcf/d |
| 2018 |
|
| 3.03 |
|
|
| (1 | ) | ||||||||
NYMEX Fixed Price | 650 MMcf/d | 2018 | 3.07 | 6 |
| 742 MMcf/d |
| 2019 |
|
| 2.73 |
|
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| (13 | ) | ||||||||
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NYMEX Three-Way Options | ||||||||||||||||||||||||
Sold call / bought put / sold put | 300 MMcf/d | 2017 | 3.07 / 2.75 / 2.27 | (2 | ) | |||||||||||||||||||
NYMEX Costless Collars | ||||||||||||||||||||||||
Sold call / bought put | 160 MMcf/d | 2017 | 3.57 / 2.96 | 1 | ||||||||||||||||||||
NYMEX Fixed Price Swaptions (3) |
| 300 MMcf/d |
| Q1 - Q2 2019 |
|
| 2.99 |
|
|
| (7 | ) | ||||||||||||
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NYMEX Call Options |
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| ||||||||||||
Sold call price | 230 MMcf/d | 2018 | 3.75 | (8 | ) |
| 230 MMcf/d |
| 2018 |
|
| 3.75 |
|
|
| - |
| |||||||
Sold call price | 230 MMcf/d | 2019 | 3.75 | (9 | ) |
| 230 MMcf/d |
| 2019 |
|
| 3.75 |
|
|
| (4 | ) | |||||||
Bought call price |
| 230 MMcf/d |
| 2019 |
|
| 3.75 |
|
|
| - |
| ||||||||||||
Sold call price |
| 230 MMcf/d |
| 2020 |
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| 3.25 |
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| 1 |
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Basis Contracts(2) | 2017 2018 2019 2020 - 2023
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| 13 60 39 25
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Basis Contracts (4) |
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| 2018 |
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| 35 |
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| 2019 |
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| 126 |
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| 2020 |
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| 88 |
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| 2021 - 2023 |
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| 18 |
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Natural Gas Fair Value Position | 128 |
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| 243 |
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Net Premiums Received on Unexpired Options |
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| (4 | ) | ||||||||||||
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Other Derivative Contracts |
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Fair Value Position | (21 | ) | ||||||||||||||||||||||
Fair Value Position |
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| (15 | ) | ||||||||||||
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Foreign Currency Contracts |
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Fair Value Position | 2017 - 2018 | 39 | ||||||||||||||||||||||
Total Fair Value Position | $ | 142 | ||||||||||||||||||||||
Fair Value Position (5) |
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| 2018 - 2019 |
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| 12 |
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Total Fair Value Position and Net Premiums Received |
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| $ | (255 | ) |
(1) | WTI Fixed Price Swaptions give the counterparty the option to extend certain Q3 - Q4 2018 Fixed Price swaps to Q1- Q2 2019. |
(2) | Encana has entered into swaps to protect against |
(3) | NYMEX Fixed Price Swaptions give the counterparty the option to extend certain Q3 - Q4 2018 Fixed Price swaps to Q1- Q2 2019. |
(4) | Encana has entered into swaps to protect against |
(5) | Encana has entered into U.S. dollar denominatedfixed-for-floating average currency swaps to protect against |
32 |
Earnings Impact of Realized and Unrealized Gains (Losses) on Risk Management Positions
Three Months Ended | Nine Months Ended |
| Three Months Ended |
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| Nine Months Ended |
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September 30, | September 30, |
| September 30, |
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| September 30, |
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2017 | 2016 | 2017 | 2016 |
| 2018 |
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| 2017 |
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| 2018 |
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| 2017 |
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Realized Gains (Losses) on Risk Management |
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Commodity and Other Derivatives: |
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Revenues(1) | $ | 41 | $ | 54 | $ | 36 | $ | 358 |
| $ | (77 | ) |
| $ | 41 |
|
| $ | (95 | ) |
| $ | 36 |
| ||||||||
Transportation and processing | - | - | (4) | (4) |
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| - |
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| - |
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| - |
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| (4 | ) | ||||||||||||
Foreign Currency Derivatives: |
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Foreign exchange | 9 | - | 8 | - |
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| 1 |
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| 9 |
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| 11 |
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| 8 |
| ||||||||||||
$ | 50 | $ | 54 | $ | 40 | $ | 354 |
| $ | (76 | ) |
| $ | 50 |
|
| $ | (84 | ) |
| $ | 40 |
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Unrealized Gains (Losses) on Risk Management |
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Commodity and Other Derivatives: |
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Revenues(2) | $ | (76) | $ | 42 | $ | 396 | $ | (469) |
| $ | (164 | ) |
| $ | (76 | ) |
| $ | (422 | ) |
| $ | 396 |
| ||||||||
Transportation and processing | - | (1) | - | 4 | ||||||||||||||||||||||||||||
Foreign Currency Derivatives: |
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Foreign exchange | 14 | - | 40 | - |
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| 9 |
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| 14 |
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| (17 | ) |
|
| 40 |
| ||||||||||||
$ | (62) | $ | 41 | $ | 436 | $ | (465) |
| $ | (155 | ) |
| $ | (62 | ) |
| $ | (439 | ) |
| $ | 436 |
| |||||||||
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Total Realized and Unrealized Gains (Losses) on Risk Management, net |
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Commodity and Other Derivatives: |
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Revenues(1) (2) | $ | (35) | $ | 96 | $ | 432 | $ | (111) |
| $ | (241 | ) |
| $ | (35 | ) |
| $ | (517 | ) |
| $ | 432 |
| ||||||||
Transportation and processing | - | (1) | (4) | - |
|
| - |
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| - |
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| - |
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| (4 | ) | ||||||||||||
Foreign Currency Derivatives: |
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Foreign exchange | 23 | - | 48 | - |
|
| 10 |
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| 23 |
|
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| (6 | ) |
|
| 48 |
| ||||||||||||
$ | (12) | $ | 95 | $ | 476 | $ | (111) |
| $ | (231 | ) |
| $ | (12 | ) |
| $ | (523 | ) |
| $ | 476 |
|
(1) | Includes realized gains of $2 million and $5 million for the three and nine months ended September 30, |
(2) | Includes unrealized losses of nil and $1 million for the three and nine months ended September 30, |
Reconciliation of Unrealized Risk Management Positions from January 1 to September 30
2017 | 2016 |
|
|
| 2018 |
|
| 2017 |
| |||||||||||||||||
Fair Value | Total Unrealized Gain (Loss) | Total Unrealized Gain (Loss) |
|
|
| Fair Value |
|
| Total Unrealized Gain (Loss) |
|
| Total Unrealized Gain (Loss) |
| |||||||||||||
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Fair Value of Contracts, Beginning of Year | $ | (292) |
|
|
| $ | 183 |
|
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|
|
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| ||||||||||
Change in Fair Value of Contracts in Place at Beginning of Year | 476 | $ | 476 | $ | (111) |
|
|
|
| (523 | ) |
| $ | (523 | ) |
| $ | 476 |
| |||||||
Settlement of Other Derivative Contracts | 5 |
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| 5 |
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Fair Value of Other Derivative Contracts Entered into During the Period | (7) | |||||||||||||||||||||||||
Fair Value of Contracts Realized During the Period | (40) | (40) | (354) |
|
|
|
| 84 |
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| 84 |
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| (40 | ) | |||||||||
Fair Value of Contracts, End of Period | $ | 142 | $ | 436 | $ | (465) | ||||||||||||||||||||
Fair Value of Contracts Outstanding |
|
|
| $ | (251 | ) |
| $ | (439 | ) |
| $ | 436 |
| ||||||||||||
Net Premiums Received on Unexpired Options |
|
|
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| (4 | ) |
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| ||||||||||||
Fair Value of Contracts and Net Premiums Received, End of Period |
|
|
| $ | (255 | ) |
|
|
|
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|
Risk management assets and liabilities arise from the use of derivative financial instruments and are measured at fair value. See Note 18 for a discussion of fair value measurements.
33 |
Unrealized Risk Management Positions
As at | As at |
| As at |
|
| As at |
| |||||||||
September 30, | December 31, |
| September 30, |
|
| December 31, |
| |||||||||
2017 | 2016 |
| 2018 |
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| 2017 |
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| |||||||||
Risk Management Assets |
|
|
|
|
|
|
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| ||||||||
Current | $ | 107 | $ | - |
| $ | 146 |
|
| $ | 205 |
| ||||
Long-term | 84 | 16 |
|
| 132 |
|
|
| 246 |
| ||||||
191 | 16 |
|
| 278 |
|
|
| 451 |
| |||||||
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| |||||||||
Risk Management Liabilities |
|
|
|
|
|
|
|
| ||||||||
Current | 17 | 254 |
|
| 450 |
|
|
| 236 |
| ||||||
Long-term | 11 | 35 |
|
| 68 |
|
|
| 13 |
| ||||||
28 | 289 |
|
| 518 |
|
|
| 249 |
| |||||||
|
|
|
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| |||||||||
Other Derivative Contracts |
|
|
|
|
|
|
|
| ||||||||
Current in accounts payable and accrued liabilities | 5 | 5 |
|
| 5 |
|
|
| 5 |
| ||||||
Long-term in other liabilities and provisions | 16 | 14 |
|
| 10 |
|
|
| 14 |
| ||||||
Net Risk Management Assets (Liabilities) and Other Derivative Contracts | $ | 142 | $ | (292 | ) |
| $ | (255 | ) |
| $ | 183 |
|
C) Credit Risk
Credit risk arises from the potential that the Company may incur a loss if a counterparty to a financial instrument fails to meet its obligation in accordance with agreed terms. While exchange-traded contracts are subject to nominal credit risk due to the financial safeguards established by the New York Stock Exchange and Toronto Stock Exchange,the TSX, over-the-counter traded contracts expose Encana to counterparty credit risk. This credit risk exposure is mitigated through the use of credit policies approved by the Board of Directors governing the Company’s credit portfolio including credit practices that limit transactions according to counterparties’ credit quality. Mitigation strategies may include master netting arrangements, requesting collateral and/or transacting credit derivatives. The Company executes commodity derivative financial instruments under master agreements that have netting provisions that provide for offsetting payables against receivables. As a result of netting provisions, the Company’s maximum exposure to loss under derivative financial instruments due to credit risk is limited to the net amounts due from the counterparties under the derivative contracts, as disclosed in Note 18. As at September 30, 2017,2018, the Company had no significant credit derivatives in place and held no collateral.
As at September 30, 2017,2018, cash equivalents include high-grade, short-term securities, placed primarily with financial institutions and companies with strong investment grade ratings. Any foreign currency agreements entered into are with major financial institutions that have investment grade credit ratings.
A substantial portion of the Company’s accounts receivable are with customers in the oil and gas industry and are subject to normal industry credit risks. As at September 30, 2017,2018, approximately 92 percent (90(92 percent as at December 31, 2016)2017) of Encana’s accounts receivable and financial derivative credit exposures were with investment grade counterparties.
As at September 30, 2017,2018, Encana had threetwo counterparties whose net settlement position individually accounted for more than 10 percent of the fair value of the outstandingin-the-money net risk management contracts by counterparty. As at September 30, 2017,2018, these counterparties accounted for 49 percent, 1169 percent and 1011 percent of the fair value of the outstandingin-the-money net risk management contracts. As at December 31, 2016,2017, Encana had one counterpartythree counterparties whose net settlement position accounted for 8456 percent, 11 percent and 11 percent of the fair value of the outstandingin-the-money net risk management contracts.
During 2015 and 2017, Encana entered into agreements resulting from divestitures, which may require Encana to fulfill certain payment obligations on the take or pay volume commitments assumed by the purchasers. The circumstances that would require Encana to perform under the agreements include events where a purchaser fails to make payment to the guaranteed party and/or a purchaser is subject to an insolvency event. The agreements have remaining terms from fourthree to sevensix years with a fair value recognized of $21$15 million as at September 30, 20172018 ($19 million as at December 31, 2016)2017). The
34 |
maximum potential amount of undiscounted future payments is $375$258 million as at September 30, 2017,2018, and is considered unlikely.
20. |
|
Supplemental disclosures to the Condensed Consolidated Statement of Cash Flows are presented below:
A) | Net Change in Non-Cash Working Capital |
|
| Three Months Ended |
|
| Nine Months Ended |
| ||||||||||
|
| September 30, |
|
| September 30, |
| ||||||||||
|
| 2018 |
|
| 2017 |
|
| 2018 |
|
| 2017 |
| ||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable and accrued revenues |
| $ | (8 | ) |
| $ | (34 | ) |
| $ | (152 | ) |
| $ | 69 |
|
Accounts payable and accrued liabilities |
|
| 59 |
|
|
| (82 | ) |
|
| 99 |
|
|
| (253 | ) |
Income tax receivable and payable |
|
| 262 |
|
|
| 214 |
|
|
| 252 |
|
|
| (7 | ) |
|
| $ | 313 |
|
| $ | 98 |
|
| $ | 199 |
|
| $ | (191 | ) |
A) Net Change inNon-Cash Working Capital
B) | Non-Cash Activities |
|
| Three Months Ended |
|
| Nine Months Ended |
| ||||||||||
|
| September 30, |
|
| September 30, |
| ||||||||||
|
| 2018 |
|
| 2017 |
|
| 2018 |
|
| 2017 |
| ||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-Cash Investing Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligation incurred (See Note 12) |
| $ | 3 |
|
| $ | 3 |
|
| $ | 13 |
|
| $ | 9 |
|
Property, plant and equipment accruals |
|
| (20 | ) |
|
| (18 | ) |
|
| 61 |
|
|
| 60 |
|
Capitalized long-term incentives |
|
| 11 |
|
|
| 30 |
|
|
| 6 |
|
|
| 30 |
|
Property additions/dispositions (swaps) |
|
| 55 |
|
|
| 28 |
|
|
| 195 |
|
|
| 193 |
|
Non-Cash Financing Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common shares issued under dividend reinvestment plan (See Note 13) |
| $ | - |
|
| $ | 1 |
|
| $ | - |
|
| $ | 1 |
|
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2017 | 2016 | 2017 | 2016 | |||||||||||||
Operating Activities | ||||||||||||||||
Accounts receivable and accrued revenues | $ (34) | $ 28 | $ 69 | $ 154 | ||||||||||||
Accounts payable and accrued liabilities | (82) | (59) | (253) | (250) | ||||||||||||
Income tax receivable and payable | 214 | (29) | (7) | 1 | ||||||||||||
$ 98 | $ (60) | $ (191) | $ (95) | |||||||||||||
B) Non-Cash Activities
|
| |||||||||||||||
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2017 | 2016 | 2017 | 2016 | |||||||||||||
Non-Cash Investing Activities | ||||||||||||||||
Asset retirement obligation incurred (See Note 11) | $ 3 | $ 2 | $ 9 | $ 6 | ||||||||||||
Property, plant and equipment accruals | (18) | (23) | 60 | (76) | ||||||||||||
Capitalized long-term incentives (See Note 16) | 30 | 15 | 30 | 25 | ||||||||||||
Property additions/dispositions | 28 | 30 | 193 | 85 | ||||||||||||
Non-Cash Financing Activities | ||||||||||||||||
Common shares issued under dividend reinvestment plan (See Note 12) | $ 1 | $ - | $ 1 | $ 1 |
21. |
|
Commitments
The following table outlines the Company’s commitments as at September 30, 2017:2018:
Expected Future Payments |
| Expected Future Payments |
| |||||||||||||||||||||||||||||||||||||||||||||||||||||
(undiscounted) | 2017 | 2018 | 2019 | 2020 | 2021 | Thereafter | Total |
| 2018 |
|
| 2019 |
|
| 2020 |
|
| 2021 |
|
| 2022 |
|
| Thereafter |
|
| Total |
| ||||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||||||||
Transportation and Processing | $ | 120 | $ | 525 | $ | 599 | $ | 573 | $ | 452 | $ | 2,761 | $ | 5,030 |
| $ | 146 |
|
| $ | 709 |
|
| $ | 688 |
|
| $ | 598 |
|
| $ | 571 |
|
| $ | 2,763 |
|
| $ | 5,475 |
| ||||||||||||||
Drilling and Field Services | 101 | 79 | 34 | 18 | 8 | - | 240 |
|
| 73 |
|
|
| 66 |
|
|
| 29 |
|
|
| 9 |
|
|
| - |
|
|
| - |
|
|
| 177 |
| |||||||||||||||||||||
Operating Leases | 4 | 18 | 16 | 16 | 15 | 61 | 130 |
|
| 4 |
|
|
| 17 |
|
|
| 17 |
|
|
| 16 |
|
|
| 16 |
|
|
| 49 |
|
|
| 119 |
| |||||||||||||||||||||
Total | $ | 225 | $ | 622 | $ | 649 | $ | 607 | $ | 475 | $ | 2,822 | $ | 5,400 |
| $ | 223 |
|
| $ | 792 |
|
| $ | 734 |
|
| $ | 623 |
|
| $ | 587 |
|
| $ | 2,812 |
|
| $ | 5,771 |
|
Included within transportation and processing in the table above are certain commitments associated with midstream service agreements with VMLP as described in Note 14.15. Divestiture transactions can reduce certain commitments disclosed above.
35 |
Encana is involved in various legal claims and actions arising in the normal course of the Company’s operations. Although the outcome of these claims cannot be predicted with certainty, the Company does not expect these matters to have a material adverse effect on Encana’s financial position, cash flows or results of operations. Management’s assessment of these matters may change in the future as certain of these matters are in early stages or are subject to a number of uncertainties. For material matters that the Company believes an unfavourable outcome is reasonably possible, the Company discloses the nature and a range of potential exposures. If an unfavourable outcome were to occur, there exists the possibility of a material impact on the Company’s consolidated net earnings or loss for the period in which the effect becomes reasonably estimable. The Company accrues for such items when a liability is both probable and the amount can be reasonably estimated. Such accruals are based on the Company’s information known about the matters, estimates of the outcomes of such matters and experience in handling similar matters.
36 |
Agreement to Acquire Newfield Exploration Company
On November 1, 2018, Encana announced that it has entered into a definitive merger agreement to acquire all of the issued and outstanding shares of common stock of Newfield Exploration Company (“Newfield”) in an all-stock transaction. Under the terms of the merger agreement, Newfield shareholders will receive 2.6719 common shares of Encana for each share of Newfield common stock. The transaction has been unanimously approved by the Board of Directors of both Encana and Newfield and is subject to the terms and conditions set forth in the merger agreement. The transaction is expected to close in the first quarter of 2019.
37 |
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The MD&A is intended to provide a narrative description of Encana’s business from management’s perspective. This MD&A should be read in conjunction with the unaudited interim Condensed Consolidated Financial Statements and accompanying notes for the period ended September 30, 20172018 (“Consolidated Financial Statements”), which are included in Part I, Item 1 of this Quarterly Report on Form10-Q and the audited Consolidated Financial Statements and accompanying notes and MD&A for the year ended December 31, 2016,2017, which are included in Items 8 and 7, respectively, of the 20162017 Annual Report on Form10-K. Common industry terms and abbreviations are used throughout this MD&A and are defined in the Definitions, Conversions and Conventions sections of this Quarterly Report on Form10-Q. This MD&A includes the following sections:
Strategy
Encana is a leading North American energy producer that is focused on developing its multi-basin portfolio of oil, NGLNGLs and natural gas producing plays. Encana is committed to growing long-term shareholder value through a disciplined focus on generating profitable growth. The Company is pursuing the key business objectives of exercising a disciplined capital allocation strategy by investing in a limited number of core assets, growing high margin liquids volumes, maximizing profitability through operating efficiencies and reducing costs, and preserving balance sheet strength.
In executing its strategy, Encana focuses on its core values of One, Agile and Driven, which guide the organization to be flexible, responsive, determined and motivated with a commitment to excellence and a passion to succeed as a unified team.
Encana continually reviews and evaluates its strategy and changing market conditions. In 2017,2018, Encana continues to focus on quality growth from high margin, scalable projects located in some of the best plays in North America, referred to as the “Core Assets”, comprising Montney and Duvernay in Canada and Eagle Ford and Permian in the U.S. These world-class assets form a multi-basin portfolio enabling flexible and efficient investment of capital. The Company rapidly deploys successful ideas and practices across these assets, becoming more efficient as innovative and sustainable technical improvements are implemented.
For additional information on Encana’s strategy, its reporting segments and the plays in which the Company operates, refer to Items 1 and 2 of the 20162017 Annual Report on Form10-K. In evaluating its operations and assessing its leverage, the Company reviews performance-based measures such asNon-GAAP Cash Flow and CorporateNon-GAAP Cash Flow Margin and debt-based metrics such as Debt to Adjusted Capitalization and Net Debt to Adjusted EBITDA, which arenon-GAAP measures and do not have any standardized meaning under U.S. GAAP. These measures may not be similar to measures presented by other issuers and should not be viewed as a substitute for measures reported under U.S. GAAP. Further information regarding these measures, including reconciliations to the closest GAAP measure, can be found in theNon-GAAP Measures section of this MD&A.
Highlights
During the first nine months of 2017,2018, Encana focused on executing its 20172018 capital plan, maintaining operational efficiencies achieved in 20162017 and seeking new ways to reduceminimizing the effect of inflationary costs. Higher benchmark pricesrevenues in the first nine months of 20172018 compared to 20162017 resulting from higher liquids benchmark prices and production volumes. Higher oil and NGL benchmark prices contributed to increases in Encana’s average realized oil NGLs and natural gasNGL prices which resulted in higher revenues. In the first nine months of 2017, Encana’s average realized oil, NGLs40 percent and natural gas prices35 percent, respectively. Liquids production volumes increased by 2932 percent 48 percent and 42 percent, respectively, compared to 2016.2017. Encana is also focused on the diversification of the Company’s downstream markets to capture higher realized prices. Encana remains committed to buildingdelivering a business model that allows the Company to adapt to fluctuating commodity prices.
Significant Developments
Received approval from the TSX to purchase, for cancellation, up to 35 million common shares pursuant to a NCIB over a 12-month period from February 28, 2018 to February 27, 2019. As of September 30, 2018, the Company has purchased approximately 20.7 million common shares for total consideration of approximately $250 million.
Completed the sale of the Company’s Pipestone liquids hub in Alberta to Keyera Partnership, a subsidiary of Keyera Corp., announced on April 2, 2018. In conjunction with the sale, Keyera will own and construct a natural gas processing facility and provide Encana with processing services under a competitive fee-for-service arrangement in support of the Company’s liquids growth plans in Montney.
|
|
Financial Results
Three months ended September 30, 20172018
Reported net earnings of $39 million, including a net loss on risk management in revenues of $241 million, before tax.
Generated cash from operating activities of $885 million, Non-GAAP Cash Flow of $589 million and Non-GAAP Cash Flow Margin of $16.93 per BOE. Paid dividends of $0.015 per common share.
|
|
|
|
Nine months ended September 30, 20172018
Reported net earnings of $39 million, including a net loss on risk management in revenues of $517 million, before tax, and a net foreign exchange loss of $93 million, before tax.
Recovered current taxes of approximately $61 million and interest of $11 million primarily resulting from the resolution of certain tax items relating to prior taxation years.
Generated cash from operating activities of $1,741 million, Non-GAAP Cash Flow of $1,575 million and Non-GAAP Cash Flow Margin of $16.63 per BOE, including the tax items noted above.
Paid dividends of $0.045 per common share.
Held cash and cash equivalents of $615 million and had available credit facilities of $4.0 billion for total liquidity of $4.6 billion at September 30, 2018.
Capital Investment
Directed $350 million, or 67 percent, of total capital spending to Permian and Montney in the third quarter of 2018 and $1,163 million, or 72 percent, during the first nine months of 2018.
Focused on highly efficient capital activity and short-cycle high margin projects providing flexibility to respond to fluctuations in commodity prices.
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|
|
|
|
|
Capital Investment
|
|
Three months ended September 30, 20172018
Produced average oil and NGL volumes of 178.7 Mbbls/d which accounted for 47 percent of total production volumes. Average oil and plant condensate production volumes of 136.5 Mbbls/d were 76 percent of total liquids production volumes.
Produced average natural gas volumes of 1,197 MMcf/d which accounted for 53 percent of total production volumes.
|
|
|
Nine months ended September 30, 20172018
Produced average oil and NGL volumes of 159.9 Mbbls/d which accounted for 46 percent of total production volumes. Average oil and plant condensate production volumes of 122.7 Mbbls/d were 77 percent of total liquids production volumes. Produced average natural gas volumes of 1,123 MMcf/d which accounted for 54 percent of total production volumes. Revenues and |
|
|
Operating Expenses
Focused on market diversification to other downstream markets to maximize realized commodity prices and revenues through a combination of derivative financial instruments and transportation contracts.
Continued to benefit from secured pipeline transportation capacity to the Dawn and Houston markets to protect against weakening AECO and Midland differentials to NYMEX and WTI, respectively; maintained access to local markets through existing transportation contracts.
Preserved operational efficiencies achieved in previous years and minimized the effect of inflationary costs.
Incurred higher transportation and processing expense in the third quarter and the first nine months of 2018 of $79 million, or 40 percent, and $182 million, or 29 percent, respectively, compared to the same periods in 2017 primarily due to higher volumes in Montney and Permian, and additional costs incurred in conjunction with the diversification of other downstream markets to capture higher realized prices.
Subsequent Events
On November 1, 2018, Encana announced that it has entered into a definitive merger agreement to acquire all of the issued and outstanding shares of common stock of Newfield Exploration Company (“Newfield”) in an all-stock transaction. Under the terms of the merger agreement, Newfield shareholders will receive 2.6719 common shares of Encana for each share of Newfield common stock. The transaction has been unanimously approved by the Board of Directors of both Encana and Newfield and is subject to the terms and conditions set forth in the merger agreement. The transaction is expected to close in the first quarter of 2019.
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2017 OutlookOn October 1, 2018, Encana announced an agreement to sell its San Juan assets, comprising approximately 182,000 net acres in New Mexico, to DJR Energy, LLC for total consideration of approximately $480 million. The transaction is expected to close in the fourth quarter of 2018, with an effective date of April 1, 2018, and is subject to the satisfaction of normal closing conditions and customary closing adjustments.
The oil and gas industry is cyclical and commodity prices are inherently volatile. Oil prices for the remainder of 20172018 are expected to reflect global supply and demand dynamics andas well as the geopolitical environment. At a meeting in May,The original OPEC decided to extend an agreement among members and certainnon-OPEC countries to cut crude oil production until the end of the first quarter of 2018. The agreement, which was implemented in January 2017 has beento limit output and the drawdowns of oil storage inventory levels were generally supportive of oil prices in 2017; however, production growth in other countries continues to partially offset the expected benefit of the OPEC agreement. OPEC is expected to meet at the end of November to further deliberate on options to rebalance the global oil market, including the possibility of extending the agreement beyond the first quarterhalf of 2018. Additionally,Trade disputes and oil supply outages in the third quarter of 2017, hurricane activity along the U.S. Gulf Coast resultedrecent months resulting from geopolitical instability in major outages in upstream production, refining capacity and transportation infrastructure. The outages haveproducing countries has created additional uncertainty for oil and gas supply which could impact prices for the remainder of the year. As well, prices could be impacted as a result of decisions made by OPEC and demand contributingcertain non-OPEC countries to increase future oil production. OPEC and certain non-OPEC countries are expected to meet again in December 2018 to review production levels and decide on a framework for permanent cooperation with allied producers to seek a balanced and sustainable global oil market. The result of this meeting could further contribute to price fluctuations.fluctuations in 2019.
Natural gas prices were stronger in the first nine months of 2017 compared to 2016 as increases in exports and industrial demand coupled with lower natural gas production alleviated much of the oversupply. Improvement in prices going forward depends on2018 will be affected by the timing of supply and demand growth; howevergrowth and the effects of weather. Natural gas prices in western Canada have seen significant negative price pressure as supply reached multi-year highs, surpassing regional demand and stressing effective pipeline capacity. Relatively strong condensate prices may also lend support to activity levels resulting in continued downward pressure on natural gas prices for the remainder of 2018. Potential for improvement in U.S. natural gas prices remains limited due to continued substantial production increases in Northeast U.S. and associated gas production in the contiguous U.S. is expected to be more than sufficient to supply continued demand growth as pipeline infrastructure additions in the U.S. Northeast help to alleviate bottlenecks and Permian Basin activity adds to associated gas production.
Company Outlook
Encana hasis positioned itself to be flexible andin the current price environment in order to continue to achieve strong returns from the Core Assets through this evolving commodity price cycle.returns. The Company released updated Corporate Guidance on July 21, 2017 to reflect the impact of divestitures and improved operational performance which included changes to liquids and natural gas production volumes, upstream operating expense, transportation and processing expense and production growth from the Core Assets. The details of Encana’s Corporate Guidance can be accessed on the Company’s website atwww.encana.com.
Encana enters into commodity derivative financial instruments on a portion of its expected oil, NGL and natural gas production volumes to reducewhich mitigate price volatility and help sustain revenues during periods of lower prices. A portion of the Company’s production is sold at prevailing market prices which also allows Encana to participate in potential price increases. As of October 31, 2017, Encana’s 2017 commodity price mitigation program covers about 70 percentat September 30, 2018, the Company has hedged approximately 137 Mbbls/d of expected totaloil and condensate production and 1,017 MMcf/d of expected natural gas production for the remainder of the year. Additional information on Encana’s hedging program can be found in Note 19 to the Consolidated Financial Statements included in Part I, Item 1 of this Quarterly Report on Form 10-Q.
Markets for crude oil and natural gas are exposed to different price risks. While the market price for crude oil tends to move in the same direction as the global market, the Permian Basin is experiencing wider differentials due to temporary local export capacity constraints. Natural gas prices may vary between geographic regions depending on local supply and demand conditions. Encana proactively utilizes transportation contracts to diversify the Company’s downstream markets and reduce significant exposure to any given market. Through a combination of derivative financial instruments and transportation capacity, Encana has mitigated the majority of its exposure to Midland and AECO pricing in 2018 and 2019. In addition, Encana continues to seek new markets to yield higher returns.
The Company released updated Corporate Guidance on November 1, 2018, revising its guidance range downward for transportation and processing expense from $7.40 to $7.75 per BOE to $7.20 to $7.40 per BOE to reflect lower cost structures than anticipated. The Company also updated its full year capital investment guidance to approximately $2.0 billion from the previous guidance range of $1.8 to $1.9 billion reflecting higher costs associated with diesel fuel, steel tariffs and delays in sourcing local sand in Eagle Ford. The updated full year capital investment guidance of approximately $2.0 billion includes current year expenditures on the Pipestone liquids hub and the San Juan assets totaling approximately $55 million. The liquids hub divestiture and previously announced sale of the San Juan assets are expected to generate proceeds totaling approximately $515 million.
Encana’s updated 2018 Corporate Guidance can be accessed on the Company’s website at www.encana.com.
Encana is on track to meet its updated full year capital investment guidance of $1.6 billion to $1.8approximately $2.0 billion. During the first nine months of 2017,2018, the Company spent $1,287 million,$1.6 billion, of which 96 percent$718 million was invested in the Core Assets with 55 percent directed to Permian where the Company has drilled 9481 net wells. wells and $445 million was directed to Montney with 108 net wells drilled. Capital investment in Permian is expected to be optimized by Encana’s cube development approach to maximize returns and recovery. Capital investment in Montney is allocated to both Cutbank Ridge and Pipestone with a focus on growing condensate volumes. The remainder of the capital investment, primarily directed to Eagle Ford and Duvernay, is expected to optimize production and margins.
Encana continually strives to improve well performance by lowering drilling and completion costs through innovative techniques such as thetechniques. Encana's large-scale cube development model characterized as autilizes multi-well pad centralized development on apads and advanced completion designs to access stacked pay resource. This approach, which is currently being applied in Permianresource to maximize returns and Montney, is helping to boost productivity and enhanceresource recovery from reservoirsits reservoirs. The impact of Encana’s disciplined capital program and continuous innovation create flexibility and opportunity to grow cash flows and production volumes going forward.
Production
As part of the Company’s long-term growth strategy, Encana has significantly shifted its production mix to a more balanced portfolio in those assets.
Production
the recent years, thereby reducing the extent of exposure to market volatility of a particular commodity. During the first nine months of 2017,2018, average liquids production volumes were 121.2159.9 Mbbls/d and average natural gas production volumes were 1,123 MMcf/d. The Company expects to deliver substantial liquids growth for the remainder of the year. The Company is on track to meet the updatedfull year 2018 guidance rangeranges for liquids production volumes of 127.0165.0 Mbbls/d to 132.0175.0 Mbbls/d and natural gas production volumes of 1,150 MMcf/d to 1,250 MMcf/d by year end as a result of expected fourththe Company’s growth plans for Montney. Encana’s growth plans for Montney are supported by third party processing plants commissioned in 2017 and the second quarter growth in Montney liquids volumes from new facilities in the playof 2018, as well as growththe completion of the Pipestone liquids hub at the end of the third quarter.
Operating Expenses
Efficiency improvements and lower service costs are expected to be maintained through the support of the Company’s culture of innovation and its focus on continuous improvement in Permian oil volumes. Average natural gas production volumes foroperational execution. As activity in the industry accelerates, Encana expects to continue pursuing innovative ways to reduce upstream operating and administrative expenses. Operating costs in the first nine months of 2017 were 1,108 MMcf/d and are expected to remain within the updated full year 2017 guidance range of 1,075 MMcf/d to 1,125 MMcf/d at year end.
Core Assets production for the first nine months of 2017 of 244.0 MBOE/d was up slightly compared to the fourth quarter of 2016 and is expected to grow as Encana sees the anticipated benefit of its increased capital program with additional wells coming online and new facilities in Montney. Total liquids production accounted for 40 percent of the Company’s total production volumes, with the Core Assets contributing 114.8 Mbbls/d or 95 percent.
Operating Expenses
To date, efficiency improvements and lower service costs have been maintained and the Company continues to benefit from transportation contract renegotiations completed in 2016. The Company reported operating costs for the first nine months of 2017 which2018 are on track to meet the updated full year 2017updated 2018 guidance ranges. Transportation and processing expense was $6.52$7.39 per BOE, while upstream operating expense and administrative expense, excluding long-term incentive costs, were $3.85$3.35 per BOE and $1.58$1.34 per BOE, respectively.
Service costs are expected to increase with higher activity in the oil and gas industry and the recovery of liquids prices. Encana continuesstrives to offset any inflationary pressures with additional efficiency gains.
Selected Financial Information
|
|
| Three months ended September 30, |
|
|
|
| Nine months ended September 30, |
| ||||||||||
($ millions) |
|
| 2018 |
|
| 2017 (1) |
|
|
|
| 2018 |
|
| 2017 (1) |
| ||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Product and Service Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Upstream product revenues |
|
| $ | 1,166 |
|
| $ | 652 |
|
|
|
| $ | 3,107 |
|
| $ | 2,119 |
|
Market optimization |
|
|
| 317 |
|
| 224 |
|
|
|
|
| 909 |
|
|
| 614 |
| |
Service revenues |
|
|
| 5 |
|
| 4 |
|
|
|
|
| 9 |
|
|
| 18 |
| |
Total Product and Service Revenues |
|
|
| 1,488 |
|
|
| 880 |
|
|
|
|
| 4,025 |
|
|
| 2,751 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gains (Losses) on Risk Management, Net |
|
|
| (241 | ) |
|
| (35 | ) |
|
|
|
| (517 | ) |
|
| 432 |
|
Sublease Revenues |
|
|
| 15 |
|
|
| 16 |
|
|
|
|
| 50 |
|
|
| 50 |
|
Total Revenues |
|
|
| 1,262 |
|
|
| 861 |
|
|
|
|
| 3,558 |
|
|
| 3,233 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Operating Expenses (2) |
|
|
| 1,143 |
|
|
| 865 |
|
|
|
|
| 3,218 |
|
|
| 2,427 |
|
Operating Income (Loss) |
|
|
| 119 |
|
|
| (4 | ) |
|
|
|
| 340 |
|
|
| 806 |
|
Total Other (Income) Expenses |
|
|
| 74 |
|
|
| (526 | ) |
|
|
|
| 356 |
|
|
| (477 | ) |
Net Earnings (Loss) Before Income Tax |
|
|
| 45 |
|
|
| 522 |
|
|
|
|
| (16 | ) |
|
| 1,283 |
|
Income Tax Expense (Recovery) |
|
|
| 6 |
|
|
| 228 |
|
|
|
|
| (55 | ) |
|
| 227 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Earnings (Loss) |
|
| $ | 39 |
|
| $ | 294 |
|
|
|
| $ | 39 |
|
| $ | 1,056 |
|
Three months ended September 30, | Nine months ended September 30, | |||||||||||||||||||
($ millions) | 2017 | 2016 | 2017 | 2016 | ||||||||||||||||
Product Revenues | $ | 646 | $ | 641 | $ | 2,112 | $ | 1,738 | ||||||||||||
Gains (Losses) on Risk Management, net | (35) | 96 | 432 | (111) | ||||||||||||||||
Market Optimization | 224 | 215 | 614 | 393 | ||||||||||||||||
Other | 26 | 27 | 75 | 76 | ||||||||||||||||
Total Revenues | 861 | 979 | 3,233 | 2,096 | ||||||||||||||||
Total Operating Expenses(1) | 865 | 851 | 2,427 | 3,923 | ||||||||||||||||
Operating Income (Loss) | (4) | 128 | 806 | (1,827) | ||||||||||||||||
Total Other (Income) Expenses | (526) | (251) | (477) | (458) | ||||||||||||||||
Net Earnings (Loss) Before Income Tax | $ | 522 | $ | 379 | $ | 1,283 | $ | (1,369) | ||||||||||||
Net Earnings (Loss) | $ | 294 | $ | 317 | $ | 1,056 | $ | (663) | ||||||||||||
(1) Total Operating Expenses include non-cash items such as DD&A, impairments, accretion of asset retirement obligations and long-term incentive costs.
|
|
(1) | 2017 revenues have been realigned to conform with the January 1, 2018 adoption of ASU 2014-09 “Revenue from Contracts with Customers”, as described in Note 2 to the Consolidated Financial Statements included in Part I, Item 1 of this Quarterly Report on Form 10-Q. |
(2) | Total Operating Expenses include non-cash items such as DD&A, accretion of asset retirement obligations and long-term incentive costs. |
Revenues
Encana’s revenues are substantially derived from sales of oil, NGLNGLs and natural gas production. Increases or decreases in Encana’s revenue, profitability and future production are highly dependent on the commodity prices the Company receives. Prices are market driven and fluctuate due to factors beyond the Company’s control, such as supply and demand, seasonality and geopolitical and economic factors. Canadian Operations realized prices are closely linked to the Edmonton Condensate and AECO, benchmark prices, except for production from Deep Panuke which is closely related to the Algonquin City Gate benchmark price due to the proximity of the offshore production platform to New England.as well as other downstream natural gas benchmarks, including Dawn. The USA Operations realized prices generally reflect WTI and NYMEX benchmark prices.prices, as well as other downstream oil benchmarks. The other downstream benchmarks reflect the diversification of the Company’s markets. Realized NGL prices are significantly influenced by oil benchmark prices and the NGL production mix. Recent trends in benchmark prices relevant to Encana are shown in the table below.
Benchmark Prices
|
| Three months ended September 30, |
|
|
| Nine months ended September 30, |
| ||||||||||||
(average for the period) |
| 2018 |
|
|
| 2017 |
|
|
| 2018 |
|
|
| 2017 |
| ||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil & NGLs |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WTI ($/bbl) |
| $ | 69.50 |
|
|
| $ | 48.21 |
|
|
| $ | 66.75 |
|
|
| $ | 49.47 |
|
Edmonton Condensate (C$/bbl) |
| $ | 87.34 |
|
|
| $ | 59.59 |
|
|
| $ | 85.30 |
|
|
| $ | 64.62 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NYMEX ($/MMBtu) |
| $ | 2.90 |
|
|
| $ | 3.00 |
|
|
| $ | 2.90 |
|
|
| $ | 3.17 |
|
AECO (C$/Mcf) |
| $ | 1.35 |
|
|
| $ | 2.04 |
|
|
| $ | 1.41 |
|
|
| $ | 2.58 |
|
Dawn (C$/MMBtu) |
| $ | 3.79 |
|
|
| $ | 3.62 |
|
|
| $ | 3.73 |
|
|
| $ | 4.01 |
|
Three months ended September 30, | Nine months ended September 30, | |||||||||||||||||||
(average for the period) | 2017 | 2016 | 2017 | 2016 | ||||||||||||||||
Oil & NGLs | ||||||||||||||||||||
WTI ($/bbl) | $ | 48.21 | $ | 44.94 | $ | 49.47 | $ | 41.33 | ||||||||||||
Edmonton Condensate (C$/bbl) | 59.59 | 56.22 | 64.62 | 53.42 | ||||||||||||||||
Natural Gas | ||||||||||||||||||||
NYMEX ($/MMBtu) | $ | 3.00 | $ | 2.81 | $ | 3.17 | $ | 2.29 | ||||||||||||
AECO (C$/Mcf) | 2.04 | 2.20 | 2.58 | 1.85 | ||||||||||||||||
Algonquin City Gate ($/MMBtu) | 2.17 | 2.82 | 3.17 | 2.85 |
Production Volumes and Realized Prices
| Three months ended September 30, |
|
| Nine months ended September 30, |
|
| |||||||||||||||||||||||||||||||
| Production Volumes (1) |
|
| Realized Prices (2) |
|
| Production Volumes (1) |
|
| Realized Prices (2) |
|
| |||||||||||||||||||||||||
| 2018 |
|
|
| 2017 |
|
| 2018 |
|
|
| 2017 |
|
| 2018 |
|
|
| 2017 |
|
| 2018 |
|
|
| 2017 |
|
| |||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Oil (Mbbls/d, $/bbl) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Canadian Operations |
| 0.3 |
|
|
|
| 0.6 |
|
| $ | 60.32 |
|
|
| $ | 31.66 |
|
|
| 0.4 |
|
|
|
| 0.5 |
|
| $ | 57.83 |
|
|
| $ | 37.25 |
|
| |
USA Operations |
| 95.2 |
|
|
|
| 74.6 |
|
|
| 66.84 |
|
|
|
| 45.78 |
|
|
| 87.3 |
|
|
|
| 72.9 |
|
|
| 65.66 |
|
|
|
| 47.07 |
|
| |
Total |
| 95.5 |
|
|
|
| 75.2 |
|
|
| 66.82 |
|
|
|
| 45.66 |
|
|
| 87.7 |
|
|
|
| 73.4 |
|
|
| 65.62 |
|
|
|
| 47.01 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
NGLs – Plant Condensate (Mbbls/d, $/bbl) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Canadian Operations |
| 36.3 |
|
|
|
| 22.8 |
|
|
| 64.82 |
|
|
|
| 46.41 |
|
|
| 31.2 |
|
|
|
| 20.7 |
|
|
| 64.61 |
|
|
|
| 47.74 |
|
| |
USA Operations |
| 4.7 |
|
|
|
| 5.1 |
|
|
| 55.23 |
|
|
|
| 36.63 |
|
|
| 3.8 |
|
|
|
| 3.1 |
|
|
| 55.12 |
|
|
|
| 38.95 |
|
| |
Total |
| 41.0 |
|
|
|
| 27.9 |
|
|
| 63.73 |
|
|
|
| 44.61 |
|
|
| 35.0 |
|
|
|
| 23.8 |
|
|
| 63.60 |
|
|
|
| 46.59 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
NGLs – Other (Mbbls/d, $/bbl) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Canadian Operations |
| 14.4 |
|
|
|
| 4.5 |
|
|
| 30.25 |
|
|
|
| 22.68 |
|
|
| 12.5 |
|
|
|
| 4.7 |
|
|
| 28.87 |
|
|
|
| 21.47 |
|
| |
USA Operations |
| 27.8 |
|
|
|
| 19.9 |
|
|
| 28.27 |
|
|
|
| 18.37 |
|
|
| 24.7 |
|
|
|
| 19.3 |
|
|
| 24.08 |
|
|
|
| 18.11 |
|
| |
Total |
| 42.2 |
|
|
|
| 24.4 |
|
|
| 28.95 |
|
|
|
| 19.16 |
|
|
| 37.2 |
|
|
| �� | 24.0 |
|
|
| 25.69 |
|
|
|
| 18.77 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Total NGLs (Mbbls/d, $/bbl) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Canadian Operations |
| 50.7 |
|
|
|
| 27.3 |
|
|
| 54.99 |
|
|
|
| 42.52 |
|
|
| 43.7 |
|
|
|
| 25.4 |
|
|
| 54.41 |
|
|
|
| 42.84 |
|
| |
USA Operations |
| 32.5 |
|
|
|
| 25.0 |
|
|
| 32.15 |
|
|
|
| 22.13 |
|
|
| 28.5 |
|
|
|
| 22.4 |
|
|
| 28.16 |
|
|
|
| 21.01 |
|
| |
Total |
| 83.2 |
|
|
|
| 52.3 |
|
|
| 46.07 |
|
|
|
| 32.75 |
|
|
| 72.2 |
|
|
|
| 47.8 |
|
|
| 44.07 |
|
|
|
| 32.61 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Total Oil & NGLs (Mbbls/d, $/bbl) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Canadian Operations |
| 51.0 |
|
|
|
| 27.9 |
|
|
| 55.03 |
|
|
|
| 42.28 |
|
|
| 44.1 |
|
|
|
| 25.9 |
|
|
| 54.44 |
|
|
|
| 42.74 |
|
| |
USA Operations |
| 127.7 |
|
|
|
| 99.6 |
|
|
| 58.01 |
|
|
|
| 39.83 |
|
|
| 115.8 |
|
|
|
| 95.3 |
|
|
| 56.45 |
|
|
|
| 40.95 |
|
| |
Total |
| 178.7 |
|
|
|
| 127.5 |
|
|
| 57.16 |
|
|
|
| 40.37 |
|
|
| 159.9 |
|
|
|
| 121.2 |
|
|
| 55.90 |
|
|
|
| 41.33 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Natural Gas (MMcf/d, $/Mcf) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Canadian Operations |
| 1,038 |
|
|
|
| 736 |
|
|
| 1.96 |
|
|
|
| 1.73 |
|
|
| 975 |
|
|
|
| 802 |
|
|
| 2.09 |
|
|
|
| 2.21 |
|
| |
USA Operations |
| 159 |
|
|
|
| 203 |
|
|
| 2.19 |
|
|
|
| 2.90 |
|
|
| 148 |
|
|
|
| 306 |
|
|
| 2.25 |
|
|
|
| 3.10 |
|
| |
Total |
| 1,197 |
|
|
|
| 939 |
|
|
| 1.99 |
|
|
|
| 1.98 |
|
|
| 1,123 |
|
|
|
| 1,108 |
|
|
| 2.11 |
|
|
|
| 2.46 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Total Production (MBOE/d, $/BOE) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Canadian Operations |
| 224.1 |
|
|
|
| 150.4 |
|
|
| 21.62 |
|
|
|
| 16.29 |
|
|
| 206.5 |
|
|
|
| 159.5 |
|
|
| 21.46 |
|
|
|
| 18.06 |
|
| |
USA Operations |
| 154.1 |
|
|
|
| 133.6 |
|
|
| 50.30 |
|
|
|
| 34.13 |
|
|
| 140.5 |
|
|
|
| 146.3 |
|
|
| 48.90 |
|
|
|
| 33.15 |
|
| |
Total |
| 378.2 |
|
|
|
| 284.0 |
|
|
| 33.30 |
|
|
|
| 24.67 |
|
|
| 347.0 |
|
|
|
| 305.8 |
|
|
| 32.57 |
|
|
|
| 25.28 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Production Mix (%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Oil & Plant Condensate |
| 36 |
|
|
|
| 36 |
|
|
|
|
|
|
|
|
|
|
|
| 35 |
|
|
|
| 32 |
|
|
|
|
|
|
|
|
|
|
| |
NGLs – Other |
| 11 |
|
|
|
| 9 |
|
|
|
|
|
|
|
|
|
|
|
| 11 |
|
|
|
| 8 |
|
|
|
|
|
|
|
|
|
|
| |
Total Oil & NGLs |
| 47 |
|
|
|
| 45 |
|
|
|
|
|
|
|
|
|
|
|
| 46 |
|
|
|
| 40 |
|
|
|
|
|
|
|
|
|
|
| |
Natural Gas |
| 53 |
|
|
|
| 55 |
|
|
|
|
|
|
|
|
|
|
|
| 54 |
|
|
|
| 60 |
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Core Assets Production |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Oil (Mbbls/d) |
| 93.5 |
|
|
|
| 71.9 |
|
|
|
|
|
|
|
|
|
|
|
| 85.5 |
|
|
|
| 69.3 |
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
NGLs – Plant Condensate (Mbbls/d) |
| 40.8 |
|
|
|
| 27.4 |
|
|
|
|
|
|
|
|
|
|
|
| 34.9 |
|
|
|
| 23.2 |
|
|
|
|
|
|
|
|
|
|
| |
NGLs – Other (Mbbls/d) |
| 41.1 |
|
|
|
| 22.9 |
|
|
|
|
|
|
|
|
|
|
|
| 36.0 |
|
|
|
| 22.3 |
|
|
|
|
|
|
|
|
|
|
| |
Total NGLs (Mbbls/d) |
| 81.9 |
|
|
|
| 50.3 |
|
|
|
|
|
|
|
|
|
|
|
| 70.9 |
|
|
|
| 45.5 |
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Total Oil & NGLs (Mbbls/d) |
| 175.4 |
|
|
|
| 122.2 |
|
|
|
|
|
|
|
|
|
|
|
| 156.4 |
|
|
|
| 114.8 |
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Natural Gas (MMcf/d) |
| 1,138 |
|
|
|
| 754 |
|
|
|
|
|
|
|
|
|
|
|
| 1,054 |
|
|
|
| 775 |
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Total Production (MBOE/d) |
| 364.9 |
|
|
|
| 248.0 |
|
|
|
|
|
|
|
|
|
|
|
| 332.0 |
|
|
|
| 244.0 |
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
% of Total Encana Production |
| 96 |
|
|
|
| 87 |
|
|
|
|
|
|
|
|
|
|
|
| 96 |
|
|
|
| 80 |
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30, | Nine months ended September 30, | |||||||||||||||||||||||||||||||||||||||||||
Production Volumes (1) |
Realized Prices(2) |
Production Volumes (1) |
Realized Prices (2) | |||||||||||||||||||||||||||||||||||||||||
2017 | 2016 | 2017 | 2016 | 2017 | 2016 | 2017 | 2016 | |||||||||||||||||||||||||||||||||||||
Oil(Mbbls/d, $/bbl) | ||||||||||||||||||||||||||||||||||||||||||||
Canadian Operations | 0.6 | 1.0 | $ | 31.66 | $ | 37.36 | 0.5 | 2.5 | $ | 37.25 | $ | 35.95 | ||||||||||||||||||||||||||||||||
USA Operations | 74.6 | 68.1 | 45.78 | 41.76 | 72.9 | 73.6 | 47.07 | 36.49 | ||||||||||||||||||||||||||||||||||||
Total | 75.2 | 69.1 | 45.66 | 41.70 | 73.4 | 76.1 | 47.01 | 36.47 | ||||||||||||||||||||||||||||||||||||
NGLs – Plant Condensate(Mbbls/d, $/bbl) | ||||||||||||||||||||||||||||||||||||||||||||
Canadian Operations | 22.8 | 19.1 | 46.41 | 40.16 | 20.7 | 17.8 | 47.74 | 39.21 | ||||||||||||||||||||||||||||||||||||
USA Operations | 5.1 | 2.7 | 36.63 | 35.83 | 3.1 | 2.7 | 38.95 | 30.37 | ||||||||||||||||||||||||||||||||||||
Total | 27.9 | 21.8 | 44.61 | 39.63 | 23.8 | 20.5 | 46.59 | 38.03 | ||||||||||||||||||||||||||||||||||||
NGLs – Other(Mbbls/d, $/bbl) | ||||||||||||||||||||||||||||||||||||||||||||
Canadian Operations | 4.5 | 6.1 | 22.68 | 20.41 | 4.7 | 8.6 | 21.47 | 10.53 | ||||||||||||||||||||||||||||||||||||
USA Operations | 19.9 | 20.0 | 18.37 | 13.11 | 19.3 | 21.3 | 18.11 | 11.16 | ||||||||||||||||||||||||||||||||||||
Total | 24.4 | 26.1 | 19.16 | 14.80 | 24.0 | 29.9 | 18.77 | 10.98 | ||||||||||||||||||||||||||||||||||||
Total NGLs(Mbbls/d, $/bbl) | ||||||||||||||||||||||||||||||||||||||||||||
Canadian Operations | 27.3 | 25.2 | 42.52 | 35.39 | 25.4 | 26.4 | 42.84 | 29.83 | ||||||||||||||||||||||||||||||||||||
USA Operations | 25.0 | 22.7 | 22.13 | 15.79 | 22.4 | 24.0 | 21.01 | 13.34 | ||||||||||||||||||||||||||||||||||||
Total | 52.3 | 47.9 | 32.75 | 26.09 | 47.8 | 50.4 | 32.61 | 21.98 | ||||||||||||||||||||||||||||||||||||
Total Oil & NGLs(Mbbls/d, $/bbl) | ||||||||||||||||||||||||||||||||||||||||||||
Canadian Operations | 27.9 | 26.2 | 42.28 | 35.47 | 25.9 | 28.9 | 42.74 | 30.36 | ||||||||||||||||||||||||||||||||||||
USA Operations | 99.6 | 90.8 | 39.83 | 35.26 | 95.3 | 97.6 | 40.95 | 30.80 | ||||||||||||||||||||||||||||||||||||
Total | 127.5 | 117.0 | 40.37 | 35.31 | 121.2 | 126.5 | 41.33 | 30.70 | ||||||||||||||||||||||||||||||||||||
Natural Gas(MMcf/d, $/Mcf) | ||||||||||||||||||||||||||||||||||||||||||||
Canadian Operations | 736 | 924 | 1.73 | 1.87 | 802 | 987 | 2.21 | 1.57 | ||||||||||||||||||||||||||||||||||||
USA Operations | 203 | 402 | 2.90 | 2.78 | 306 | 433 | 3.10 | 2.11 | ||||||||||||||||||||||||||||||||||||
Total | 939 | 1,326 | 1.98 | 2.15 | 1,108 | 1,420 | 2.46 | 1.73 | ||||||||||||||||||||||||||||||||||||
Total Production(MBOE/d, $/BOE) | ||||||||||||||||||||||||||||||||||||||||||||
Canadian Operations | 150.4 | 180.2 | 16.29 | 14.74 | 159.5 | 193.3 | 18.06 | 12.55 | ||||||||||||||||||||||||||||||||||||
USA Operations | 133.6 | 157.8 | 34.13 | 27.36 | 146.3 | 169.8 | 33.15 | 23.10 | ||||||||||||||||||||||||||||||||||||
Total | 284.0 | 338.0 | 24.67 | 20.64 | 305.8 | 363.1 | 25.28 | 17.48 | ||||||||||||||||||||||||||||||||||||
Production Mix(%) | ||||||||||||||||||||||||||||||||||||||||||||
Oil & Plant Condensate | 36 | 27 | 32 | 27 | ||||||||||||||||||||||||||||||||||||||||
NGLs – Other | 9 | 8 | 8 | 8 | ||||||||||||||||||||||||||||||||||||||||
Total Oil & NGLs | 45 | 35 | 40 | 35 | ||||||||||||||||||||||||||||||||||||||||
Natural Gas | 55 | 65 | 60 | 65 | ||||||||||||||||||||||||||||||||||||||||
Core Assets Production | ||||||||||||||||||||||||||||||||||||||||||||
Oil (Mbbls/d) | 71.9 | 61.7 | 69.3 | 65.1 | ||||||||||||||||||||||||||||||||||||||||
NGLs – Plant Condensate (Mbbls/d) | 27.4 | 20.9 | 23.2 | 19.2 | ||||||||||||||||||||||||||||||||||||||||
NGLs – Other (Mbbls/d) | 22.9 | 21.9 | 22.3 | 23.8 | ||||||||||||||||||||||||||||||||||||||||
Total NGLs (Mbbls/d) | 50.3 | 42.8 | 45.5 | 43.0 | ||||||||||||||||||||||||||||||||||||||||
Total Oil & NGLs (Mbbls/d) | 122.2 | 104.5 | 114.8 | 108.1 | ||||||||||||||||||||||||||||||||||||||||
Natural Gas (MMcf/d) | 754 | 830 | 775 | 911 | ||||||||||||||||||||||||||||||||||||||||
Total Production (MBOE/d) | 248.0 | 242.8 | 244.0 | 259.9 | ||||||||||||||||||||||||||||||||||||||||
% of Total Encana Production | 87 | 72 | 80 | 72 |
(1) | Average daily. |
(2) | Averageper-unit prices, excluding the impact of risk management activities. |
Three months ended September 30, | Nine months ended September 30, |
| Three months ended September 30, |
|
| Nine months ended September 30, |
| |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Natural | Natural |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||||||||||||||||
($ millions) | Oil | NGLs (1) | Gas | Total | Oil | NGLs (1) | Gas | Total |
| Oil |
|
| NGLs (1) |
|
| Natural Gas (2) |
|
| Total |
|
| Oil |
|
| NGLs (1) |
|
| Natural Gas (2) |
|
| Total |
| ||||||||||||||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||||||||||||||||||
2016 Product Revenues | $ | 266 | $ | 114 | $ | 261 | $ | 641 | $ | 761 | $ | 303 | $ | 674 | $ | 1,738 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
2017 Upstream Product Revenues |
| $ | 317 |
|
| $ | 156 |
|
| $ | 173 |
|
| $ | 646 |
|
| $ | 942 |
|
| $ | 425 |
|
| $ | 745 |
|
| $ | 2,112 |
| ||||||||||||||||||||||||||||||||||||||
Increase (decrease) due to: |
|
|
|
|
|
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Sales prices | 28 | 32 | (4 | ) | 56 | 211 | 137 | 229 | 577 |
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| 184 |
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| 92 |
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| 10 |
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Production volumes | 23 | 10 | (84 | ) | (51 | ) | (30 | ) | (15 | ) | (158 | ) | (203 | ) |
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| 185 |
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| 248 |
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| (39 | ) |
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| 394 |
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2017 Product Revenues | $ | 317 | $ | 156 | $ | 173 | $ | 646 | $ | 942 | $ | 425 | $ | 745 | $ | 2,112 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
(1) Includes plant condensate. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
2018 Upstream Product Revenues |
| $ | 587 |
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| $ | 354 |
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| $ | 219 |
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| $ | 1,160 |
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| $ | 1,572 |
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| $ | 868 |
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| $ | 647 |
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| $ | 3,087 |
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(1) | Includes plant condensate. |
(2) | Natural gas revenues for the third quarter and the first nine months of 2018 exclude a royalty adjustment with no associated production volumes of $6 million and $20 million, respectively (2017 - $6 million and $7 million, respectively). |
Oil Revenues
Three months ended September 30, 20172018 versus September 30, 20162017
Oil revenues increased $51$270 million compared to the third quarter of 20162017 primarily due to:
Higher average realized oil prices of $21.16 per bbl, or 46 percent, increased revenues by $184 million. The increase reflected a higher WTI benchmark price which was up 44 percent and exposure to other downstream benchmark prices in 2018 resulting from the diversification of the Company’s markets, partially offset by weakening regional pricing in USA Operations; and
Higher average oil production volumes of 20.3 Mbbls/d increased revenues by $86 million. Higher volumes were primarily due to a successful drilling program in Permian (24.3 Mbbls/d), partially offset by natural declines in Eagle Ford (3.0 Mbbls/d).
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Nine months ended September 30, 20172018 versus September 30, 20162017
Oil revenues increased $181$630 million compared to the first nine months of 20162017 primarily due to:
Higher average realized oil prices of $18.61 per bbl, or 40 percent, increased revenues by $445 million. The increase reflected a higher WTI benchmark price which was up 35 percent and exposure to other downstream benchmark prices in 2018 resulting from the diversification of the Company’s markets; and
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Higher average oil production volumes of 14.3 Mbbls/d increased revenues by $185 million. Higher volumes were primarily due to a successful drilling program in Permian (20.5 Mbbls/d), partially offset by:by natural declines in Eagle Ford (3.8 Mbbls/d) andasset sales (1.2 Mbbls/d), which mainly include the Tuscaloosa Marine Shale assets in the second quarter of 2017 and thePiceance natural gas assets in the third quarter of 2017.
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NGL Revenues
Three months ended September 30, 20172018 versus September 30, 20162017
NGL revenues increased $42$198 million compared to the third quarter of 20162017 primarily due to:
Higher average realized NGL prices of $13.32 per bbl, or 41 percent, increased revenues by $92 million. The increase reflected higher WTI and Edmonton Condensate benchmark prices which were up 44 percent and 47 percent, respectively, as well as benchmark prices for other NGLs; and
Higher average NGL production volumes of 30.9 Mbbls/d increased revenues by $106 million. Higher volumes were due to successful drilling programs in Montney and Permian (36.1 Mbbls/d), partially offset by natural declines in Duvernay and Eagle Ford (3.6 Mbbls/d).
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Nine months ended September 30, 20172018 versus September 30, 20162017
NGL revenues increased $122$443 million compared to the first nine months of 20162017 primarily due to:
Higher average realized NGL prices of $11.46 per bbl, or 35 percent, increased revenues by $195 million. The increase reflected higher WTI and Edmonton Condensate benchmark prices which were up 35 percent and 32 percent, respectively, as well as benchmark prices for other NGLs; and
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Higher average NGL production volumes of 24.4 Mbbls/d increased revenues by $248 million. Higher volumes were primarily due to successful drilling programs in Montney and Permian (29.7 Mbbls/d), partially offset by:by natural declines in Duvernay (2.1 Mbbls/d), increased downtime resulting from scheduled plant maintenance for processing liquids rich volumes in Montney (1.2 Mbbls/d) and asset sales (1.1 Mbbls/d), which mainly include the Piceance natural gas assets in the third quarter of 2017 and certain assets in Wheatland in the fourth quarter of 2017.
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Natural Gas Revenues
Three months ended September 30, 20172018 versus September 30, 20162017
Natural gas revenues decreased $88increased $46 million compared to the third quarter of 20162017 primarily due to:
Slightly higher average realized natural gas prices of $0.01 per Mcf, or one percent, increased revenues by $10 million. The increase reflected exposure to other downstream benchmark prices in 2018 resulting from the diversification of the Company’s markets, partially offset by lower NYMEX and AECO benchmark prices which were down three percent and 34 percent, respectively, and lower regional pricing in USA Operations; and
Higher average natural gas production volumes of 258 MMcf/d increased revenues by $36 million. Higher volumes were due to successful drilling programs in Montney and Permian (347 MMcf/d) and decreased downtime primarily resulting from scheduled plant maintenance in Montney in 2017 (54 MMcf/d), partially offset by asset sales (121 MMcf/d), which mainly included certain assets in Wheatland in the fourth quarter of 2017 and the Piceance natural gas assets in the third quarter of 2017, and natural declines in Duvernay (12 MMcf/d) and in Other Upstream Operations (11 MMcf/d) in the third quarter of 2018.
Nine months ended September 30, 2018 versus September 30, 2017
Natural gas revenues decreased $98 million compared to the first nine months of 2017 primarily due to:
Lower average realized natural gas prices of $0.35 per Mcf, or 14 percent, decreased revenues by $59 million. The decrease reflected lower NYMEX and AECO benchmark prices which were down nine percent and 45 percent, respectively, as well as lower regional pricing in USA Operations, partially offset by exposure to other downstream benchmark prices in 2018 resulting from the diversification of the Company’s markets; and
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