| · | | ASUASU 2014-09, “Revenue from Contracts with Customers” under Topic 606. The new standard replaces Topic 605, “Revenue Recognition” as well as other industry-specific guidance within the Accounting Standards Codification. Topic 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. The standard has been applied using the modified retrospective approach and did not have a material impact on the Company’s Condensed Consolidated Financial Statements, other than enhancing disclosures related to the disaggregation of revenues from contracts with customers and performance obligations. The disclosures required under Topic 606 are included in Note 4, Revenues from Contracts with Customers.
ASU 2017-07, “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 has been applied retrospectively for the presentation of net periodic pension costs and net periodic postretirement benefit cost, whereas prospective adoption has been applied to the capitalization of the service cost component. | · | | 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 has been applied retrospectively for the presentation of net periodic pension costs and net periodic postretirement benefit cost, whereas prospective adoption has been applied to the capitalization of the service cost component.
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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.Balance 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, in additionaccordance with Topic 840. Encana intends to elect this optional transition method, as well as certain practical expedients permitted under Topic 842, which will allow the Company to retain the classification of leases assessed under Topic 840 whichthat commenced prior to adoption. In January 2018, FASB issued Encana also intends to adopt the transitional practical expedient provided under ASU2018-01, “Land Easement Practical Expedient for Transition to Topic 842”, which permits entities issued by FASB in January 2018. This amendment applies to elect an optional transition practical expedient for land easements that existed or expired prior to adoption of Topic 842 and were 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. Encana intends to elect this transitional practical expedient.
Encana continues to review and analyze contracts, identify its portfolio of leased assets, gather the necessary terms and data elements, as well as identify the processes and controls required to support the accounting for leases and related disclosures. The Company is in the early stagesprocess of implementing and testing a lease software system which will facilitate the measurement and required disclosures for operating leases. The Company anticipates the software implementation to be complete by the end of 2018.2018, 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 Topic 842 at this time, the Company anticipates there will be a material impactan increase in right-of-use assets and lease liabilities on the Consolidated Financial Statements resulting from the recognition of assets and liabilities from operating lease activities.Balance Sheet. As of January 1, 2019, Encana will be required to adopt ASU2018-02 “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 to the Company’s Consolidated Financial Statements. As a result, the Company does not intend to 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.
3. | 3. Segmented Information
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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. · | | 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.
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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. · | | 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.
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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. · | | 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.
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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.
Results of Operations (For the three months ended March 31)September 30) Segment and Geographic Information | | | Canadian Operations | | | USA Operations | | | Market Optimization | | | Canadian Operations | | | USA Operations | | | Market Optimization | | | | 2018 | | | 2017 (1) | | | 2018 | | 2017 (1) | | | 2018 | | 2017 (1) | | | 2018 | | | 2017 (1) | | | 2018 | | | 2017 (1) | | | 2018 | | | 2017 (1) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Revenues | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Product and service revenues | | $ | 404 | | | $ | 301 | | | $ | 555 | | | $ | 447 | | | $ | 301 | | | $ | 186 | | | $ | 453 | | | $ | 235 | | | $ | 718 | | | $ | 421 | | | $ | 317 | | | $ | 224 | | Gains (losses) on risk management, net | | | 12 | | | | (21 | ) | | | (44 | ) | | (3 | ) | | | - | | | | - | | | | 8 | | | | 25 | | | | (84 | ) | | | 16 | | | | (1 | ) | | | - | | Sublease revenues | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | Total Revenues | | | 416 | | | | 280 | | | | 511 | | | 444 | | | | 301 | | | 186 | | | | 461 | | | | 260 | | | | 634 | | | | 437 | | | | 316 | | | | 224 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Operating Expenses | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Production, mineral and other taxes | | | 4 | | | | 5 | | | | 25 | | | 24 | | | | - | | | | - | | | | 4 | | | | 6 | | | | 41 | | | | 21 | | | | - | | | | - | | Transportation and processing | | | 190 | | | | 132 | | | | 27 | | | 59 | | | | 32 | | | 21 | | | | 211 | | | | 138 | | | | 34 | | | | 31 | | | | 33 | | | | 30 | | Operating | | | 29 | | | | 31 | | | | 74 | | | 87 | | | | 4 | | | 9 | | | | 34 | | | | 36 | | | | 80 | | | | 81 | | | | 8 | | | | 11 | | Purchased product | | | - | | | | - | | | | - | | | | - | | | | 273 | | | 171 | | | | - | | | | - | | | | - | | | | - | | | | 282 | | | | 202 | | Depreciation, depletion and amortization | | | 77 | | | | 64 | | | | 185 | | | 106 | | | | - | | | | - | | | | 95 | | | | 53 | | | | 241 | | | | 139 | | | | - | | | | 1 | | Total Operating Expenses | | | 300 | | | | 232 | | | | 311 | | | 276 | | | | 309 | | | 201 | | | | 344 | | | | 233 | | | | 396 | | | | 272 | | | | 323 | | | | 244 | | Operating Income (Loss) | | $ | 116 | | | $ | 48 | | | $ | 200 | | | $ | 168 | | | $ | (8 | ) | | $ | (15 | ) | | $ | 117 | | | $ | 27 | | | $ | 238 | | | $ | 165 | | | $ | (7 | ) | | $ | (20 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | Corporate & Other | | | Consolidated | | | | | | | | | | 2018 | | 2017 (1) | | | 2018 | | 2017 (1) | | | | | | | | | | Revenues | | | | | | | | | | | | | | Product and service revenues | | | | | | $ | - | | | $ | - | | | $ | 1,260 | | | $ | 934 | | | Gains (losses) on risk management, net | | | | | | | 68 | | | 362 | | | | 36 | | | 338 | | | Sublease revenues | | | | | | | 17 | | | 17 | | | | 17 | | | 17 | | | Total Revenues | | | | | | | 85 | | | 379 | | | | 1,313 | | | 1,289 | | | | | | | | | | Operating Expenses | | | | | | | | | | | | | | Production, mineral and other taxes | | | | | | | - | | | | - | | | | 29 | | | 29 | | | Transportation and processing | | | | | | | - | | | | - | | | | 249 | | | 212 | | | Operating | | | | | | | 4 | | | 5 | | | | 111 | | | 132 | | | Purchased product | | | | | | | - | | | | - | | | | 273 | | | 171 | | | Depreciation, depletion and amortization | | | | | | | 13 | | | 17 | | | | 275 | | | 187 | | | Accretion of asset retirement obligation | | | | | | | 8 | | | 11 | | | | 8 | | | 11 | | | Administrative | | | | | | | 31 | | | 58 | | | | 31 | | | 58 | | | Total Operating Expenses | | | | | | | 56 | | | 91 | | | | 976 | | | 800 | | | Operating Income (Loss) | | | | | | $ | 29 | | | $ | 288 | | | | 337 | | | 489 | | | | | | | | Other (Income) Expenses | | | | | | | | | | | | | | Interest | | | | | | | | | | | 92 | | | 88 | | | Foreign exchange (gain) loss, net | | | | | | | | | | | 91 | | | (26 | ) | | (Gain) loss on divestitures, net | | | | | | | | | | | (3 | ) | | 1 | | | Other (gains) losses, net | | | | | | | | | | | (3 | ) | | (8 | ) | | Total Other (Income) Expenses | | | | | | | | | | | 177 | | | 55 | | | Net Earnings (Loss) Before Income Tax | | | | | | | | | | | 160 | | | | 434 | | | Income tax expense (recovery) | | | | | | | | | | | 9 | | | 3 | | | Net Earnings (Loss) | | | | | | | | | | $ | 151 | | | $ | 431 | | |
| | | | | | 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) | Corporate interest income of $8 million previously reported in revenues and operating income (loss) in Q1 2017 has been reclassified to other (gains) losses, net. The remaining Q1 2017 revenues have been realigned to conform with the current year presentation.January 1, 2018 adoption of ASU 2014-09 “Revenue from Contracts with Customers”.
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Results of Operations (For the nine months ended September 30) IntersegmentSegment and Geographic Information
| | | | | | | | | | | | | | | | | | | | | | | | | | | Market Optimization | | | | Marketing Sales | | | Upstream Eliminations | | | Total | | For the three months ended March 31, | | 2018 | | | 2017 | | | 2018 | | | 2017 | | | 2018 | | | 2017 | | | | | | | | | Revenues | | $ | 1,331 | | | $ | 956 | | | $ | (1,030 | ) | | $ | (770 | ) | | $ | 301 | | | $ | 186 | | | | | | | | | Operating Expenses | | | | | | | | | | | | | | | | | | | | | | | | | Transportation and processing | | | 106 | | | | 64 | | | | (74 | ) | | | (43 | ) | | | 32 | | | | 21 | | Operating | | | 4 | | | | 9 | | | | - | | | | - | | | | 4 | | | | 9 | | Purchased product | | | 1,229 | | | | 898 | | | | (956 | ) | | | (727 | ) | | | 273 | | | | 171 | | Operating Income (Loss) | | $ | (8 | ) | | $ | (15 | ) | | $ | - | | | $ | - | | | $ | (8 | ) | | $ | (15 | ) | | Capital Expenditures | | | | | Three Months Ended March 31, | | | | | | | | | | | | | | | | 2018 | | | 2017 | | | | | | | | | Canadian Operations | | | | | | | | | | | | | | | | | | $ | 168 | | | $ | 88 | | USA Operations | | | | | | | | | | | | | | | | | | | 338 | | | | 311 | | Corporate & Other | | | | | | | | | | | | | | | | | | | 2 | | | | - | | | | | | | | | | | | | | | | | | | | $ | 508 | | | $ | 399 | | | Goodwill, Property, Plant and Equipment and Total Assets by Segment | | | | Goodwill | | | Property, Plant and Equipment | | | Total Assets | | | | As at | | | As at | | | As at | | | | March 31, 2018 | | | December 31, 2017 | | | March 31, 2018 | | | December 31, 2017 | | | March 31, 2018 | | | December 31, 2017 | | | | | | | | | Canadian Operations | | $ | 678 | | | $ | 696 | | | $ | 920 | | | $ | 862 | | | $ | 1,923 | | | $ | 1,908 | | USA Operations | | | 1,913 | | | | 1,913 | | | | 6,710 | | | | 6,555 | | | | 9,432 | | | | 9,301 | | Market Optimization | | | - | | | | - | | | | 1 | | | | 2 | | | | 151 | | | | 152 | | Corporate & Other | | | - | | | | - | | | | 1,486 | | | | 1,535 | | | | 3,604 | | | | 3,906 | | | | $ | 2,591 | | | $ | 2,609 | | | $ | 9,117 | | | $ | 8,954 | | | $ | 15,110 | | | $ | 15,267 | |
| | Canadian Operations | | | USA Operations | | | Market Optimization | | | | 2018 | | | 2017 (1) | | | 2018 | | | 2017 (1) | | | 2018 | | | 2017 (1) | | | | | | | | | | | | | | | | | | | | | | | | | | | Revenues | | | | | | | | | | | | | | | | | | | | | | | | | Product and service revenues | | $ | 1,236 | | | $ | 801 | | | $ | 1,880 | | | $ | 1,336 | | | $ | 909 | | | $ | 614 | | Gains (losses) on risk management, net | | | 93 | | | | 6 | | | | (185 | ) | | | 30 | | | | (3 | ) | | | - | | Sublease revenues | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | Total Revenues | | | 1,329 | | | | 807 | | | | 1,695 | | | | 1,366 | | | | 906 | | | | 614 | | | | | | | | | | | | | | | | | | | | | | | | | | | Operating Expenses | | | | | | | | | | | | | | | | | | | | | | | | | Production, mineral and other taxes | | | 12 | | | | 16 | | | | 97 | | | | 64 | | | | - | | | | - | | Transportation and processing | | | 608 | | | | 403 | | | | 92 | | | | 141 | | | | 99 | | | | 73 | | Operating | | | 98 | | | | 89 | | | | 238 | | | | 252 | | | | 25 | | | | 23 | | Purchased product | | | - | | | | - | | | | - | | | | - | | | | 803 | | | | 565 | | Depreciation, depletion and amortization | | | 257 | | | | 170 | | | | 628 | | | | 368 | | | | 1 | | | | 1 | | Total Operating Expenses | | | 975 | | | | 678 | | | | 1,055 | | | | 825 | | | | 928 | | | | 662 | | Operating Income (Loss) | | $ | 354 | | | $ | 129 | | | $ | 640 | | | $ | 541 | | | $ | (22 | ) | | $ | (48 | ) |
| | | | | | 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”. |
Intersegment Information | | | | | | | | | | Market Optimization | | | | | | | | | | | | Marketing Sales | | | Upstream Eliminations | | | Total | | For the three months ended September 30, | | 2018 | | | 2017 | | | 2018 | | | 2017 | | | 2018 | | | 2017 | | | | | | | | | | | | | | | | | | | | | | | | | | | Revenues | | $ | 1,513 | | | $ | 918 | | | $ | (1,197 | ) | | $ | (694 | ) | | $ | 316 | | | $ | 224 | | | | | | | | | | | | | | | | | | | | | | | | | | | Operating Expenses | | | | | | | | | | | | | | | | | | | | | | | | | Transportation and processing | | | 120 | | | | 72 | | | | (87 | ) | | | (42 | ) | | | 33 | | | | 30 | | Operating | | | 8 | | | | 11 | | | | - | | | | - | | | | 8 | | | | 11 | | Purchased product | | | 1,392 | | | | 854 | | | | (1,110 | ) | | | (652 | ) | | | 282 | | | | 202 | | Depreciation, depletion and amortization | | | - | | | | 1 | | | | - | | | | - | | | | - | | | | 1 | | Operating Income (Loss) | | $ | (7 | ) | | $ | (20 | ) | | $ | - | | | $ | - | | | $ | (7 | ) | | $ | (20 | ) |
| | 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 | |
4. | 4. Revenues from Contracts with Customers
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The table below summarizesfollowing 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 | | For the three months ended March 31, | | 2018 | | | 2017 | | | 2018 | | | 2017 | | | 2018 | | | 2017 | | | | | | | | | Revenues from Customers | | | | | | | | | | | | | | | | | | | | | | | | | Product revenues(1) | | | | | | | | | | | | | | | | | | | | | | | | | Oil | | $ | 3 | | | $ | 2 | | | $ | 473 | | | $ | 301 | | | $ | 22 | | | $ | 37 | | NGLs | | | 180 | | | | 95 | | | | 52 | | | | 40 | | | | 2 | | | | 12 | | Natural gas | | | 221 | | | | 203 | | | | 32 | | | | 107 | | | | 273 | | | | 127 | | Service revenues | | | | | | | | | | | | | | | | | | | | | | | | | Gathering and processing | | | 2 | | | | 4 | | | | - | | | | 6 | | | | - | | | | - | | Product and Service Revenues | | | 406 | | | | 304 | | | | 557 | | | | 454 | | | | 297 | | | | 176 | | | | | | | | | Other Revenues | | | | | | | | | | | | | | | | | | | | | | | | | Gains (losses) on risk management, net(2) | | | 12 | | | | (21 | ) | | | (44 | ) | | | (3 | ) | | | - | | | | - | | Sublease revenues | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | Other Revenues | | | 12 | | | | (21 | ) | | | (44 | ) | | | (3 | ) | | | - | | | | - | | Total Revenues | | $ | 418 | | | $ | 283 | | | $ | 513 | | | $ | 451 | | | $ | 297 | | | $ | 176 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Corporate & Other | | | Consolidated | | | | | | | | | | 2018 | | | 2017(3) | | | 2018 | | | 2017(3) | | | | | | | | | Revenues from Customers | | | | | | | | | | | | | | | | | | | | | | | | | Product revenues(1) | | | | | | | | | | | | | | | | | | | | | | | | | Oil | | | | | | | | | | $ | - | | | $ | - | | | $ | 498 | | | $ | 340 | | NGLs | | | | | | | | | | | - | | | | - | | | | 234 | | | | 147 | | Natural gas | | | | | | | | | | | - | | | | - | | | | 526 | | | | 437 | | Service revenues | | | | | | | | | | | | | | | | | | | | | | | | | Gathering and processing | | | | | | | | | | | - | | | | - | | | | 2 | | | | 10 | | Product and Service Revenues | | | | | | | | | | | - | | | | - | | | | 1,260 | | | | 934 | | | | | | | | | Other Revenues | | | | | | | | | | | | | | | | | | | | | | | | | Gains (losses) on risk management, net(2) | | | | | | | | | | | 68 | | | | 362 | | | | 36 | | | | 338 | | Sublease revenues | | | | | | | | | | | 17 | | | | 17 | | | | 17 | | | | 17 | | Other Revenues | | | | | | | | | | | 85 | | | | 379 | | | | 53 | | | | 355 | | Total Revenues | | | | | | | | | | $ | 85 | | | $ | 379 | | | $ | 1,313 | | | $ | 1,289 | |
| | 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 andOperations, USA Operations includesand Market Optimization include realized gains/(losses) on risk management. Corporate & Other includes unrealized gains/(losses) on risk management. |
(3) | Corporate interest income of $8 million previously reported in revenues in Q1 2017 has been reclassified to other (gains) losses, net.16
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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 March 31,September 30, 2018, receivables and accrued revenues from contracts with customers were $658$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 March 31,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
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 March 31,September 30, 2018. | | | | | | Three Months Ended | | | Nine Months Ended | | | | Three Months Ended March 31, | | | September 30, | | | September 30, | | | | 2018 | | | 2017 | | | 2018 | | | 2017 | | | 2018 | | | 2017 | | | | | | | | | | | | | | | | | | | | | Interest Expense on: | | | | | | | | | | | | | | | | | | | | | Debt | | $ | 66 | | | $ | 66 | | | $ | 67 | | | $ | 67 | | | $ | 200 | | | $ | 200 | | The Bow office building | | | 16 | | | | 16 | | | | 16 | | | | 16 | | | | 48 | | | | 47 | | Capital leases | | | 5 | | | | 5 | | | | 3 | | | | 6 | | | | 12 | | | | 16 | | Other | | | 5 | | | | 1 | | | | 6 | | | | 12 | | | | 5 | | | | 5 | | | | $ | 92 | | | $ | 88 | | | $ | 92 | | | $ | 101 | | | $ | 265 | | | $ | 268 | |
6. | 6. Foreign Exchange (Gain) Loss, Net
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| | 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.
| | | | | | | | | | | Three Months Ended March 31, | | | | 2018 | | | 2017 | | | | | Unrealized Foreign Exchange (Gain) Loss on: | | | | | | | | | Translation of U.S. dollar financing debt issued from Canada | | $ | 122 | | | $ | (33 | ) | Translation of U.S. dollar risk management contracts issued from Canada | | | 9 | | | | (4 | ) | Translation of intercompany notes | | | 19 | | | | 1 | | | | | 150 | | | | (36 | ) | | | | Foreign Exchange on Settlements of: | | | | | | | | | U.S. dollar risk management contracts issued from Canada | | | (7 | ) | | | (1 | ) | Intercompany notes | | | (50 | ) | | | 2 | | Other Monetary Revaluations | | | (2 | ) | | | 9 | | | | $ | 91 | | | $ | (26 | ) |
| | 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 | % |
| | | | | | | | | | | Three Months Ended March 31, | | | | 2018 | | | 2017 | | | | | Current Tax | | | | | | | | | Canada | | $ | - | | | $ | (42 | ) | United States | | | 1 | | | | - | | Other Countries | | | 2 | | | | 3 | | Total Current Tax Expense (Recovery) | | | 3 | | | | (39 | ) | | | | Deferred Tax | | | | | | | | | Canada | | | (3 | ) | | | 18 | | United States | | | 4 | | | | 15 | | Other Countries | | | 5 | | | | 9 | | Total Deferred Tax Expense (Recovery) | | | 6 | | | | 42 | | Income Tax Expense (Recovery) | | $ | 9 | | | $ | 3 | | Effective Tax Rate | | | 5.6% | | | | 0.7% | |
Encana’s interim income tax expense is determined using anthe 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, 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 threenine months ended March 31,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 ratesrate of 5.6 percent and 0.7343.8 percent for the threenine months ended March 31,September 30, 2018 and March 31,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 respectively, areis lower than the Canadian statutory 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 well as the items discussed above. During the threenine months ended March 31,September 30, 2018, there was no change to the provisional tax adjustment recognized in 2017 resulting from there-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.
8. | 8. Acquisitions and Divestitures
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| | | Three Months Ended | | | Three Months Ended | | | Nine Months Ended | | | | March 31, | | | September 30, | | | September 30, | | | | 2018 | | | 2017 | | | 2018 | | | 2017 | | | 2018 | | | 2017 | | | | | | | | | | | | | | | | | | | | | Acquisitions | | | | | | | | | | | | | | | | | | | | | | Canadian Operations | | $ | 2 | | | $ | 31 | | | $ | 15 | | | $ | - | | | $ | 17 | | | $ | 31 | | USA Operations | | | - | | | 15 | | | | - | | | | 2 | | | | - | | | | 19 | | Total Acquisitions | | | 2 | | | 46 | | | | 15 | | | | 2 | | | | 17 | | | | 50 | | | | | | | | | | | | | | | | | | | | | Divestitures | | | | | | | | | | | | | | | | | | | | | | Canadian Operations | | | (13) | | | (3) | | | | 2 | | | | (20 | ) | | | (55 | ) | | | (26 | ) | USA Operations | | | (6) | | | | - | | | | (26 | ) | | | (605 | ) | | | (34 | ) | | | (684 | ) | Total Divestitures | | | (19) | | | (3) | | | | (24 | ) | | | (625 | ) | | | (89 | ) | | | (710 | ) | Net Acquisitions & (Divestitures) | | $ | (17) | | | $ | 43 | | | $ | (9 | ) | | $ | (623 | ) | | $ | (72 | ) | | $ | (660 | ) |
Acquisitions For the threenine months ended March 31,September 30, 2018, acquisitions in the Canadian and USA Operations were $2$17 million (2017 - $31 million) and nil (2017 - $15$19 million), respectively, which primarily included land purchases with oil and liquids rich potential. Divestitures ForIn the threeCanadian Operations, divestitures during the nine months ended March 31,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 andOperations 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, 2018 were $13$26 million (2017 - $3 million) and $6$34 million, (2017 - nil), respectively, which primarily included the sale of 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. Amounts received from the Company’s divestiture transactions have been deducted from the respective Canadian and U.S. full cost pools. 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.
9. | 9. Property, Plant and Equipment, Net
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| | | As at March 31, 2018 | | | As at December 31, 2017 | | | 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 | | $ | 14,366 | | | $ | (13,743 | ) | | $ | 623 | | | $ | 14,555 | | | $ | (14,047 | ) | | $ | 508 | | | $ | 14,685 | | | $ | (13,869 | ) | | $ | 816 | | | $ | 14,555 | | | $ | (14,047 | ) | | $ | 508 | | Unproved properties | | | 262 | | | | - | | | | 262 | | | 311 | | | | - | | | 311 | | | | 255 | | | | - | | | | 255 | | | | 311 | | | | - | | | | 311 | | Other | | | 35 | | | | - | | | | 35 | | | 43 | | | | - | | | 43 | | | | 27 | | | | - | | | | 27 | | | | 43 | | | | - | | | | 43 | | | | | 14,663 | | | | (13,743 | ) | | | 920 | | | 14,909 | | | (14,047 | ) | | 862 | | | | 14,967 | | | | (13,869 | ) | | | 1,098 | | | | 14,909 | | | | (14,047 | ) | | | 862 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | USA Operations | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Proved properties | | | 26,081 | | | | (23,426 | ) | | | 2,655 | | | 25,610 | | | (23,240 | ) | | 2,370 | | | | 27,116 | | | | (23,869 | ) | | | 3,247 | | | | 25,610 | | | | (23,240 | ) | | | 2,370 | | Unproved properties | | | 4,039 | | | | - | | | | 4,039 | | | 4,169 | | | | - | | | 4,169 | | | | 3,709 | | | | - | | | | 3,709 | | | | 4,169 | | | | - | | | | 4,169 | | Other | | | 16 | | | | - | | | | 16 | | | 16 | | | | - | | | 16 | | | | 17 | | | | - | | | | 17 | | | | 16 | | | | - | | | | 16 | | | | | 30,136 | | | | (23,426 | ) | | | 6,710 | | | 29,795 | | | (23,240 | ) | | 6,555 | | | | 30,842 | | | | (23,869 | ) | | | 6,973 | | | | 29,795 | | | | (23,240 | ) | | | 6,555 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Market Optimization | | | 7 | | | | (6 | ) | | | 1 | | | 7 | | | (5 | ) | | 2 | | | | 7 | | | | (6 | ) | | | 1 | | | | 7 | | | | (5 | ) | | | 2 | | Corporate & Other | | | 2,244 | | | | (758 | ) | | | 1,486 | | | 2,299 | | | (764 | ) | | 1,535 | | | | 2,236 | | | | (775 | ) | | | 1,461 | | | | 2,299 | | | | (764 | ) | | | 1,535 | | | | $ | 47,050 | | | $ | (37,933 | ) | | $ | 9,117 | | | $ | 47,010 | | | $ | (38,056 | ) | | $ | 8,954 | | | $ | 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 $39$159 million, which have been capitalized during the threenine months ended March 31,September 30, 2018 (2017 - $54$146 million). Included in Corporate and Other are $61$58 million ($63 million as at December 31, 2017) of international property costs, which have been fully impaired. 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 March 31,September 30, 2018, the total carrying value of assets under capital lease was $45$43 million ($46 million as at December 31, 2017), net of accumulated amortization of $672$673 million ($684 million as at December 31, 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 11. Other Arrangement As at March 31,September 30, 2018, Corporate and Other property, plant and equipment and total assets include a carrying value of $1,216$1,200 million ($1,255 million as at December 31, 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 11.
| | | As at | | | As at | | | As at | | | As at | | | | March 31, | | | December 31, | | | September 30, | | | December 31, | | | | 2018 | | | 2017 | | | 2018 | | | 2017 | | | | | | | | | | | | | U.S. Dollar Denominated Debt | | | | | | | | | | | | | | U.S. Unsecured Notes: | | | | | | | | | | | | | | 6.50% due May 15, 2019 | | $ | 500 | | | $ | 500 | | | $ | 500 | | | $ | 500 | | 3.90% due November 15, 2021 | | | 600 | | | 600 | | | | 600 | | | | 600 | | 8.125% due September 15, 2030 | | | 300 | | | 300 | | | | 300 | | | | 300 | | 7.20% due November 1, 2031 | | | 350 | | | 350 | | | | 350 | | | | 350 | | 7.375% due November 1, 2031 | | | 500 | | | 500 | | | | 500 | | | | 500 | | 6.50% due August 15, 2034 | | | 750 | | | 750 | | | | 750 | | | | 750 | | 6.625% due August 15, 2037 | | | 462 | | | 462 | | | | 462 | | | | 462 | | 6.50% due February 1, 2038 | | | 505 | | | 505 | | | | 505 | | | | 505 | | 5.15% due November 15, 2041 | | | 244 | | | 244 | | | | 244 | | | | 244 | | Total Principal | | | 4,211 | | | 4,211 | | | | 4,211 | | | | 4,211 | | | | | | | | | | | | | Increase in Value of Debt Acquired | | | 25 | | | 26 | | | | 24 | | | | 26 | | Unamortized Debt Discounts and Issuance Costs | | | (38) | | | (40) | | | | (37 | ) | | | (40 | ) | Current Portion of Long-Term Debt | | | - | | | | - | | | | (500 | ) | | | - | | | | $ | 4,198 | | | $ | 4,197 | | | $ | 3,698 | | | $ | 4,197 | |
As at March 31,September 30, 2018, total long-term debt had a carrying value of $4,198 million and a fair value of $4,909$4,766 million (as at December 31, 2017 - carrying value of $4,197 million and a fair value of $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. 11. | 11. Other Liabilities and Provisions
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| | | As at | | | As at | | | As at | | | As at | | | | March 31, | | | December 31, | | | September 30, | | | December 31, | | | | 2018 | | | 2017 | | | 2018 | | | 2017 | | | | | | | | | | | | | The Bow Office Building | | $ | 1,304 | | | $ | 1,344 | | | $ | 1,293 | | | $ | 1,344 | | Capital Lease Obligations | | | 275 | | | 295 | | | | 233 | | | | 295 | | Unrecognized Tax Benefits | | | 197 | | | 202 | | | | 172 | | | | 202 | | Pensions and Other Post-Employment Benefits | | | 116 | | | 116 | | | | 121 | | | | 116 | | Long-Term Incentive Costs (See Note 16) | | | 32 | | | 175 | | | | 67 | | | | 175 | | Other Derivative Contracts (See Notes 18, 19) | | | 13 | | | 14 | | | | 10 | | | | 14 | | Other | | | 21 | | | 21 | | | | 20 | | | | 21 | | | | $ | 1,958 | | | $ | 2,167 | | | $ | 1,916 | | | $ | 2,167 | |
The Bow Office Building As described in Note 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. | | | 2018 | | 2019 | | 2020 | | 2021 | | 2022 | | Thereafter | | Total | | | 2018 | | | 2019 | | | 2020 | | | 2021 | | | 2022 | | | Thereafter | | | Total | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Expected Future Lease Payments | | $ | 55 | | | $ | 75 | | | $ | 75 | | | $ | 76 | | | $ | 76 | | | $ | 1,260 | | | $ | 1,617 | | | $ | 18 | | | $ | 74 | | | $ | 75 | | | $ | 76 | | | $ | 76 | | | $ | 1,255 | | | $ | 1,574 | | Less: Amounts Representing Interest | | | 47 | | | 63 | | | 61 | | | 61 | | | 60 | | | 781 | | | | 1,073 | | | | 16 | | | | 62 | | | | 62 | | | | 61 | | | | 60 | | | | 777 | | | | 1,038 | | Present Value of Expected Future Lease Payments | | $ | 8 | | | $ | 12 | | | $ | 14 | | | $ | 15 | | | $ | 16 | | | $ | 479 | | | $ | 544 | | | Present Value of Expected Future | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Lease Payments | | | $ | 2 | | | $ | 12 | | | $ | 13 | | | $ | 15 | | | $ | 16 | | | $ | 478 | | | $ | 536 | | Sublease Recoveries (undiscounted) | | $ | (27 | ) | | $ | (37 | ) | | $ | (37 | ) | | $ | (37 | ) | | $ | (38 | ) | | $ | (619 | ) | | $ | (795 | ) | | $ | (9 | ) | | $ | (37 | ) | | $ | (37 | ) | | $ | (37 | ) | | $ | (37 | ) | | $ | (617 | ) | | $ | (774 | ) | Capital Lease Obligations | | | As described in Note 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 15. | | | The total expected future lease payments related to the Company’s capital lease obligations are outlined below. | | | | | 2018 | | 2019 | | 2020 | | 2021 | | 2022 | | Thereafter | | Total | | | | Expected Future Lease Payments | | $ | 75 | | | $ | 99 | | | $ | 99 | | | $ | 87 | | | $ | 8 | | | $ | 38 | | | $ | 406 | | | Less: Amounts Representing Interest | | | 15 | | | 15 | | | 10 | | | 4 | | | 2 | | | 5 | | | | 51 | | | Present Value of Expected Future Lease Payments | | $ | 60 | | | $ | 84 | | | $ | 89 | | | $ | 83 | | | $ | 6 | | | $ | 33 | | | $ | 355 | | |
Capital Lease Obligations As described in Note 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 15. The total expected future lease payments related to the Company’s capital lease obligations are outlined below. | | 2018 | | | 2019 | | | 2020 | | | 2021 | | | 2022 | | | Thereafter | | | Total | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Expected Future Lease Payments | | $ | 25 | | | $ | 99 | | | $ | 99 | | | $ | 87 | | | $ | 8 | | | $ | 38 | | | $ | 356 | | Less: Amounts Representing Interest | | | 5 | | | | 15 | | | | 10 | | | | 4 | | | | 2 | | | | 5 | | | | 41 | | Present Value of Expected Future Lease Payments | | $ | 20 | | | $ | 84 | | | $ | 89 | | | $ | 83 | | | $ | 6 | | | $ | 33 | | | $ | 315 | |
12. | | | | | | | 12. Asset Retirement Obligation
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| | As at | | | As at | | | | September 30, | | | December 31, | | | | 2018 | | | 2017 | | | | | | | | | | | Asset Retirement Obligation, Beginning of Year | | $ | 514 | | | $ | 687 | | Liabilities Incurred and Acquired | | | 13 | | | | 11 | | Liabilities Settled and Divested | | | (28 | ) | | | (333 | ) | Change in Estimated Future Cash Outflows | | | - | | | | 88 | | Accretion Expense | | | 24 | | | | 37 | | Foreign Currency Translation | | | (12 | ) | | | 24 | | Asset Retirement Obligation, End of Period | | $ | 511 | | | $ | 514 | | | | | | | | | | | Current Portion | | $ | 104 | | | $ | 44 | | Long-Term Portion | | | 407 | | | | 470 | | | | $ | 511 | | | $ | 514 | |
| | | | | | | | | | | As at March 31, 2018 | | | As at December 31, 2017 | | | | | Asset Retirement Obligation, Beginning of Year | | $ | 514 | | | $ | 687 | | Liabilities Incurred and Acquired | | | 5 | | | | 11 | | Liabilities Settled and Divested | | | (4 | ) | | | (333 | ) | Change in Estimated Future Cash Outflows | | | - | | | | 88 | | Accretion Expense | | | 8 | | | | 37 | | Foreign Currency Translation | | | (11 | ) | | | 24 | | Asset Retirement Obligation, End of Period | | $ | 512 | | | $ | 514 | | | | | Current Portion | | $ | 69 | | | $ | 44 | | Long-Term Portion | | | 443 | | | | 470 | | | | $ | 512 | | | $ | 514 | |
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 March 31, 2018 | | | As at December 31, 2017 | | | 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 | | | 973.1 | | | $ | 4,757 | | | | 973.0 | | | $ | 4,756 | | | | 973.1 | | | $ | 4,757 | | | | 973.0 | | | $ | 4,756 | | Common Shares Purchased | | | (10.0 | ) | | | (50 | ) | | | - | | | | - | | | | (20.7 | ) | | | (102 | ) | | | - | | | | - | | Common Shares Issued Under Dividend Reinvestment Plan | | | - | | | | - | | | | 0.1 | | | | 1 | | | | - | | | | - | | | | 0.1 | | | | 1 | | Common Shares Outstanding, End of Period | | | 963.1 | | | $ | 4,707 | | | | 973.1 | | | $ | 4,757 | | | | 952.4 | | | $ | 4,655 | | | | 973.1 | | | $ | 4,757 | |
During the threenine months ended March 31,September 30, 2018, Encana issued 23,02340,057 common shares totaling $0.3$0.5 million under the Company’s dividend reinvestment plan (“DRIP”). During the twelve months ended December 31, 2017, Encana issued 58,480 common shares totaling $0.6 million under the DRIP. Dividends During the three months ended March 31,September 30, 2018, Encana paid dividends of $0.015 per common share totaling $15$14 million (2017 - $0.015 per common share totaling $15 million). During the nine months ended September 30, 2018, Encana paid dividends of $0.045 per common share totaling $43 million (2017 - $0.045 per common share totaling $44 million). For the three and nine months ended March 31,September 30, 2018, the dividends paid included $0.3$0.1 million and $0.5 million, respectively, in common shares issued in lieu of cash dividends under the DRIP (2017(for the three and nine months ended September 30, 2017 - $0.2 million)million and $0.5 million, respectively). On April 30,October 31, 2018, the Board of Directors declared a dividend of $0.015 per common share payable on June 29,December 31, 2018 to common shareholders of record as of June 15,December 14, 2018. Normal Course Issuer Bid 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 normal course issuer bid (“NCIB”)NCIB over a12-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. DuringFor the threenine months ended March 31,September 30, 2018, the Company purchased 10approximately 20.7 million common shares for total consideration of approximately $111$250 million. Of the amount paid, $50$102 million was charged to share capital and $61$148 million was charged to accumulated deficit.
Earnings Per Common Share The following table presents the computation of net earnings (loss) per common share: | | | | | | Three Months Ended | | | | Nine Months Ended | | | | Three Months Ended March 31, | | | | September 30, | | | | September 30, | | (US$ millions, except per share amounts) | | 2018 | | | 2017 | | | | 2018 | | | 2017 | | | | 2018 | | | 2017 | | | | | | | | | | | | | | | | | | | | | | | Net Earnings (Loss) | | $ | 151 | | | $ | 431 | | | | $ | 39 | | | $ | 294 | | | | $ | 39 | | | $ | 1,056 | | | | | | | | | | | | | | | | | | | | | | | Number of Common Shares: | | | | | | | | | | | | | | | | | | | | | | | Weighted average common shares outstanding - Basic | | | 971.5 | | | | 973.0 | | | | | 955.1 | | | | 973.1 | | | | | 962.2 | | | | 973.1 | | Effect of dilutive securities | | | - | | | | - | | | | | - | | | | - | | | | | - | | | | - | | Weighted average common shares outstanding - Diluted | | | 971.5 | | | | 973.0 | | | Weighted Average Common Shares Outstanding - Diluted | | | | | 955.1 | | | | 973.1 | | | | | 962.2 | | | | 973.1 | | | | | | | | | | | | | | | | | | | | | | | Net Earnings (Loss) per Common Share Basic & Diluted | | $ | 0.16 | | | $ | 0.44 | | | Net Earnings (Loss) per Common Share | | | | | | | | | | | | | | | | | | | | Basic & Diluted | | | | $ | 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 March 31,September 30, 2018 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 upon vesting of the RSUs and in accordance with the terms of the RSU Plan and Grant Agreement. The Company currently settles vested RSUs in cash. As a result, RSUs are not considered potentially dilutive securities. 14. | | | 14. | | Accumulated Other Comprehensive Income |
| | | | | | Three Months Ended | | | Nine Months Ended | | | | Three Months Ended March 31, | | | September 30, | | | September 30, | | | | 2018 | | | 2017 | | | 2018 | | | 2017 | | | 2018 | | | 2017 | | | | | | | | | | | | | | | | | | | | | Foreign Currency Translation Adjustment | | | | | | | | | | | | | | | | | | | | | | Balance, Beginning of Year | | $ | 1,029 | | | $ | 1,200 | | | Balance, Beginning of Period | | | $ | 1,028 | | | $ | 1,125 | | | $ | 1,029 | | | $ | 1,200 | | Change in Foreign Currency Translation Adjustment | | | 24 | | | (16 | ) | | | 22 | | | | (97 | ) | | | 21 | | | | (172 | ) | Balance, End of Period | | $ | 1,053 | | | $ | 1,184 | | | $ | 1,050 | | | $ | 1,028 | | | $ | 1,050 | | | $ | 1,028 | | | | | | | | | | | | | | | | | | | | | Pension and Other Post-Employment Benefit Plans | | | | | | | | | | | | | | | | | | | | | | Balance, Beginning of Year | | $ | 13 | | | $ | 10 | | | Balance, Beginning of Period | | | $ | 12 | | | $ | 9 | | | $ | 13 | | | $ | 10 | | Reclassification of Net Actuarial (Gains) and Losses to Net Earnings (See Note 17) | | | (1 | ) | | (1 | ) | | | - | | | | - | | | | (1 | ) | | | (1 | ) | Income Taxes | | | | - | | | | - | | | | - | | | | - | | Curtailment in Net Defined Periodic Benefit Cost (See Note 17) | | | | - | | | | (1 | ) | | | - | | | | (1 | ) | Income Taxes | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | Balance, End of Period | | $ | 12 | | | $ | 9 | | | $ | 12 | | | $ | 8 | | | $ | 12 | | | $ | 8 | | Total Accumulated Other Comprehensive Income | | $ | 1,065 | | | $ | 1,193 | | | $ | 1,062 | | | $ | 1,036 | | | $ | 1,062 | | | $ | 1,036 | |
15. | 15. Variable Interest Entities
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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 March 31,September 30, 2018, Encana had a capital lease obligation of $296$259 million ($314 million as at December 31, 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 March 31,September 30, 2018, VMLP provides approximately 1,1101,240 MMcf/d of natural gas gathering and compression and 600977 MMcf/d of natural gas processing under long-term service agreements with remaining terms ranging from up to 13 to 27 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 $2,390$2,425 million as at March 31,September 30, 2018. The estimate comprises the take or pay volume commitments and the potential payout of minimum costs. The take or pay volume commitments associated with certain gathering and processing assets are included in Note 21 under Transportation and Processing. The potential payout requirement is highly uncertain as the amount is contingent on future production estimates, pace of development and the amount of capacity contracted to third parties. As at March 31,September 30, 2018, there were no accounts payable and accrued liabilities outstanding related to the take or pay commitment. 16. | 16. Compensation Plans
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Encana has a number of compensation arrangements under which the Company awards various types of long-term incentive grants to eligible employees and Directors. They may include TSARs, Performance TSARs, SARs, Performance Share Units (“PSUs”), Deferred Share Units (“DSUs”) and RSUs. These compensation arrangements are share-based. Encana accounts for TSARs, Performance TSARs, SARs, PSUs and RSUs held by employees as cash-settled share-based payment transactions and, accordingly, accrues compensation costs over the vesting period based on the fair value of the rights determined using the Black-Scholes-Merton and other fair value models.
The following weighted average assumptions were used to determine the fair value of the share units held by employees:outstanding: | | | As at March 31, 2018 | | | As at March 31, 2017 | | | As at September 30, 2018 | | | As at September 30, 2017 | | | | US$ 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 | | | 1.79% | | | | 1.79% | | | | 0.74% | | | | 0.74% | | | 2.18% | | 2.18% | | | 1.53% | | 1.53% | | Dividend Yield | | | 0.55% | | | | 0.54% | | | | 0.51% | | | | 0.51% | | | 0.46% | | 0.46% | | | 0.51% | | 0.53% | | Expected Volatility Rate(1) | | | 58.46% | | | | 54.78% | | | | 58.12% | | | | 54.02% | | | 55.44% | | 51.90% | | | 59.35% | | 55.21% | | Expected Term | | | 2.0 yrs | | | | 2.1 yrs | | | | 1.9 yrs | | | | 1.9 yrs | | | 1.6 yrs | | 2.0 yrs | | | 1.6 yrs | | 1.7 yrs | | Market Share Price | | | US$11.00 | | | | C$14.17 | | | | US$11.71 | | | | C$15.58 | | | 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 March 31, | | | Three Months Ended September 30, | | | Nine Months Ended September 30, | | | | 2018 | | | 2017 | | | 2018 | | | 2017 | | | 2018 | | | 2017 | | | | | | | | | | | | | | | | | | | | | Total Compensation Costs of Transactions Classified as Cash-Settled | | $ | (27 | ) | | $ | 34 | | | $ | 36 | | | $ | 91 | | | $ | 118 | | | $ | 84 | | Less: Total Share-Based Compensation Costs Capitalized | | | 9 | | | (11 | ) | | | (11 | ) | | | (30 | ) | | | (33 | ) | | | (30 | ) | Total Share-Based Compensation Expense (Recovery) | | $ | (18 | ) | | $ | 23 | | | $ | 25 | | | $ | 61 | | | $ | 85 | | | $ | 54 | | | | | | | | | | | | | | | | | | | | | Recognized on the Condensed Consolidated Statement of Earnings in: | | | | | | | | | | | | | | | | | | | | | | Operating | | $ | (6 | ) | | $ | 8 | | | $ | 8 | | | $ | 18 | | | $ | 24 | | | $ | 18 | | Administrative | | | (12 | ) | | 15 | | | | 17 | | | | 43 | | | | 61 | | | | 36 | | | | $ | (18 | ) | | $ | 23 | | | $ | 25 | | | $ | 61 | | | $ | 85 | | | $ | 54 | |
As at March 31,September 30, 2018, the liability for share-based payment transactions totaled $217$357 million ($327 million as at December 31, 2017), of which $185$290 million ($152 million as at December 31, 2017) is recognized in accounts payable and accrued liabilities and $32$67 million ($175 million as at December 31, 2017) is recognized in other liabilities and provisions in the Condensed Consolidated Balance Sheet. | | | As at March 31, 2018 | | | As at December 31, 2017 | | | | | | As at September 30, 2018 | | As at December 31, 2017 | | | | | | | | | | | | | | | | | Liability for Cash-Settled Share-Based Payment Transactions: | | | | | | | | | | | | | | | | | | Unvested | | $ | 167 | | | $ | 274 | | | | | | | $ | 287 | | | $ | 274 | | Vested | | 50 | | | 53 | | | | | | | | 70 | | | | 53 | | | | $ | 217 | | | $ | 327 | | | | | | | $ | 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 RSUs were granted at the volume-weighted average trading price of Encana’s common shares for the five days prior to the grant date. | | | | | ThreeNine Months Ended March 31,September 30, 2018 (thousands of units) | | | | | | | | | | TSARs | | | 872 | | SARs | | | 359377 | | PSUs | | | 2,5032,546 | | DSUs | | | 3145 | | RSUs | | | 5,2385,358 | |
17. | | Pension and Other Post-Employment Benefits |
The Company has recognized total benefit plans expense which includes pension benefits and other post-employment benefits (“OPEB”) for the threenine months ended March 31September 30 as follows: | | | Pension Benefits | | | OPEB | | | Total | | | Pension Benefits | | | OPEB | | | Total | | | | 2018 | | | 2017 | | | 2018 | | | 2017 | | | 2018 | | | 2017 | | | 2018 | | | 2017 | | | 2018 | | | 2017 | | | 2018 | | | 2017 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Net Defined Periodic Benefit Cost | | $ | - | | | $ | - | | | $ | 2 | | | $ | 2 | | | $ | 2 | | | $ | 2 | | | $ | 1 | | | $ | - | | | $ | 5 | | | $ | 1 | | | $ | 6 | | | $ | 1 | | Defined Contribution Plan Expense | | | 6 | | | | 6 | | | | - | | | | - | | | | 6 | | | | 6 | | | | 17 | | | | 17 | | | | - | | | | - | | | | 17 | | | | 17 | | Total Benefit Plans Expense | | $ | 6 | | | $ | 6 | | | $ | 2 | | | $ | 2 | | | $ | 8 | | | $ | 8 | | | $ | 18 | | | $ | 17 | | | $ | 5 | | | $ | 1 | | | $ | 23 | | | $ | 18 | |
Of the total benefit plans expense, $17 million (2017 - $18 million) was included in operating expense, $6 million (2017 - $6 million) was included in operatingadministrative expense and $2 milliona gain of nil (2017 - $2$6 million) was included in administrative expense.other (gains) losses, net. The net defined periodic benefit cost for the threenine months ended March 31September 30 is as follows: | | | Defined Benefits | | | OPEB | | | Total | | | Defined Benefits | | | OPEB | | | Total | | | | 2018 | | 2017 | | | 2018 | | 2017 | | | 2018 | | 2017 | | | 2018 | | | 2017 | | | 2018 | | | 2017 | | | 2018 | | | 2017 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Service Cost | | $ | - | | | $ | - | | | $ | 2 | | | $ | 2 | | | $ | 2 | | | $ | 2 | | | $ | 1 | | | $ | 1 | | | $ | 5 | | | $ | 6 | | | $ | 6 | | | $ | 7 | | Interest Cost | | | 2 | | | 2 | | | | 1 | | | 1 | | | | 3 | | | 3 | | | | 5 | | | | 6 | | | | 2 | | | | 2 | | | | 7 | | | | 8 | | Expected Return on Plan Assets | | | (2) | | | (2) | | | | - | | | | - | | | | (2) | | | (2) | | | | (6 | ) | | | (7 | ) | | | - | | | | - | | | | (6 | ) | | | (7 | ) | Amounts Reclassified from Accumulated Other Comprehensive Income: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Amortization of net actuarial (gains) and losses | | | - | | | | - | | | | (1) | | | (1) | | | | (1) | | | (1) | | | | 1 | | | | - | | | | (2 | ) | | | (1 | ) | | | (1 | ) | | | (1 | ) | Curtailment | | | | - | | | | - | | | | - | | | | (1 | ) | | | - | | | | (1 | ) | Curtailment | | | | - | | | | - | | | | - | | | | (5 | ) | | | - | | | | (5 | ) | Total Net Defined Periodic Benefit Cost(1) | | $ | - | | | $ | - | | | $ | 2 | | | $ | 2 | | | $ | 2 | | | $ | 2 | | | $ | 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. | 18. Fair Value Measurements
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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.
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 March 31, 2018 | | Level 1 Quoted Prices in Active Markets | | Level 2 Other Observable Inputs | | 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 | | | Total Fair Value | | | Netting (1) | | | Carrying Amount | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Risk Management Assets | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Commodity Derivatives: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Current assets | | $ | - | | | $ | 267 | | | $ | - | | | $ | 267 | | | $ | (53 | ) | | $ | 214 | | | $ | 13 | | | $ | 200 | | | $ | - | | | $ | 213 | | | $ | (77 | ) | | $ | 136 | | Long-term assets | | | - | | | | 298 | | | | - | | | | 298 | | | | (8 | ) | | | 290 | | | | - | | | | 144 | | | | - | | | | 144 | | | | (14 | ) | | | 130 | | Foreign Currency Derivatives: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Current assets | | | - | | | | 12 | | | | - | | | | 12 | | | | - | | | | 12 | | | | - | | | | 10 | | | | - | | | | 10 | | | | - | | | | 10 | | Long-term assets | | | | - | | | | 2 | | | | - | | | | 2 | | | | - | | | | 2 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Risk Management Liabilities | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Commodity Derivatives: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Current liabilities | | $ | - | | | $ | 241 | | | $ | 62 | | | $ | 303 | | | $ | (53 | ) | | $ | 250 | | | $ | - | | | $ | 405 | | | $ | 122 | | | $ | 527 | | | $ | (77 | ) | | $ | 450 | | Long-term liabilities | | | - | | | | 25 | | | | - | | | | 25 | | | | (8 | ) | | | 17 | | | | - | | | | 56 | | | | 26 | | | | 82 | | | | (14 | ) | | | 68 | | Foreign Currency Derivatives: | | | | | | | | | | | | | | | | | | | | | | | | | | Current liabilities | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Other Derivative Contracts | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Current in accounts payable and accrued liabilities | | $ | - | | | $ | 5 | | | $ | - | | | $ | 5 | | | $ | - | | | $ | 5 | | | $ | - | | | $ | 5 | | | $ | - | | | $ | 5 | | | $ | - | | | $ | 5 | | Long-term in other liabilities and provisions | | | - | | | | 13 | | | | - | | | | 13 | | | | - | | | | 13 | | | | - | | | | 10 | | | | - | | | | 10 | | | | - | | | | 10 | |
As at December 31, 2017 | | Level 1 Quoted Prices in Active Markets | | | Level 2 Other Observable Inputs | | | Level 3 Significant Unobservable Inputs | | | Total Fair Value | | | Netting (1) | | | Carrying Amount | | | | | | | | | | | | | | | | | | | | | | | | | | | Risk Management Assets | | | | | | | | | | | | | | | | | | | | | | | | | Commodity Derivatives: | | | | | | | | | | | | | | | | | | | | | | | | | Current assets | | $ | - | | | $ | 189 | | | $ | - | | | $ | 189 | | | $ | (15 | ) | | $ | 174 | | Long-term assets | | | - | | | | 248 | | | | - | | | | 248 | | | | (2 | ) | | | 246 | | Foreign Currency Derivatives: | | | | | | | | | | | | | | | | | | | | | | | | | Current assets | | | - | | | | 31 | | | | - | | | | 31 | | | | - | | | | 31 | | | | | | | | | | | | | | | | | | | | | | | | | | | Risk Management Liabilities | | | | | | | | | | | | | | | | | | | | | | | | | Commodity Derivatives: | | | | | | | | | | | | | | | | | | | | | | | | | Current liabilities | | $ | 3 | | | $ | 196 | | | $ | 51 | | | $ | 250 | | | $ | (15 | ) | | $ | 235 | | Long-term liabilities | | | - | | | | 15 | | | | - | | | | 15 | | | | (2 | ) | | | 13 | | Foreign Currency Derivatives: | | | | | | | | | | | | | | | | | | | | | | | | | Current liabilities | | | - | | | | 1 | | | | - | | | | 1 | | | | - | | | | 1 | | | | | | | | | | | | | | | | | | | | | | | | | | | Other Derivative Contracts | | | | | | | | | | | | | | | | | | | | | | | | | Current in accounts payable and accrued liabilities | | $ | - | | | $ | 5 | | | $ | - | | | $ | 5 | | | $ | - | | | $ | 5 | | Long-term in other liabilities and provisions | | | - | | | | 14 | | | | - | | | | 14 | | | | - | | | | 14 | |
(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. |
| | | | | | | | | | | | | | | | | | | | | | | | | As at December 31, 2017 | | Level 1 Quoted Prices in Active Markets | | | Level 2 Other Observable Inputs | | | Level 3 Significant Unobservable Inputs | | | Total Fair Value | | | Netting (1) | | | Carrying Amount | | | | | | | | | Risk Management Assets | | | | | | | | | | | | | | | | | | | | | | | | | Commodity Derivatives: | | | | | | | | | | | | | | | | | | | | | | | | | Current assets | | $ | - | | | $ | 189 | | | $ | - | | | $ | 189 | | | $ | (15 | ) | | $ | 174 | | Long-term assets | | | - | | | | 248 | | | | - | | | | 248 | | | | (2 | ) | | | 246 | | Foreign Currency Derivatives: | | | | | | | | | | | | | | | | | | | | | | | | | Current assets | | | - | | | | 31 | | | | - | | | | 31 | | | | - | | | | 31 | | | | | | | | | Risk Management Liabilities | | | | | | | | | | | | | | | | | | | | | | | | | Commodity Derivatives: | | | | | | | | | | | | | | | | | | | | | | | | | Current liabilities | | $ | 3 | | | $ | 196 | | | $ | 51 | | | $ | 250 | | | $ | (15 | ) | | $ | 235 | | Long-term liabilities | | | - | | | | 15 | | | | - | | | | 15 | | | | (2 | ) | | | 13 | | Foreign Currency Derivatives: | | | | | | | | | | | | | | | | | | | | | | | | | Current liabilities | | | - | | | | 1 | | | | - | | | | 1 | | | | - | | | | 1 | | | | | | | | | Other Derivative Contracts | | | | | | | | | | | | | | | | | | | | | | | | | Current in accounts payable and accrued liabilities | | $ | - | | | $ | 5 | | | $ | - | | | $ | 5 | | | $ | - | | | $ | 5 | | Long-term in other liabilities and provisions | | | - | | | | 14 | | | | - | | | | 14 | | | | - | | | | 14 | |
(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.
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The Company’s Level 1 and Level 2 risk management assets and liabilities consist of commodity fixed price contracts, 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.
Level 3 Fair Value Measurements As at March 31,September 30, 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 threenine months ended March 31September 30 is presented below: | | | | | | | | | | Risk Management | | Risk Management | | | | | | | | | | 2018 | | | 2017 | | 2018 | | | 2017 | | | | | | | | | | | | | | Balance, Beginning of Year | | | | | | | | $ | (51) | | | $ (36) | | $ | (51 | ) | | $ | (36 | ) | Total Gains (Losses) | | | | | | | | | 6 | | | 41 | | | (177 | ) | | | 38 | | Purchases, Sales, Issuances and Settlements: | | | | | | | | | | | | | | | | | | | | Purchases, sales and issuances | | | | | | | | | - | | | - | | | - | | | | - | | Settlements | | | | | | | | | (17) | | | - | | | 80 | | | | (9 | ) | Transfers Out of Level 3(1) | | | | | | | | | - | | | - | | | - | | | | - | | Balance, End of Period | | | | | | | | $ | (62) | | | $ 5 | | $ | (148 | ) | | $ | (7 | ) | Change in Unrealized Gains (Losses) Related to Assets and Liabilities Held at End of Period | | | | | | | | $ | (24) | | | $ 40 | | $ | (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: | | | | | | | | | | | | | | | As at | | | As at | | | | | | | | | | March 31, | | | December 31, | | | | Valuation Technique | | Unobservable Input | | | | 2018 | | | 2017 | | | | | | | Risk Management - WTI Options | | Option Model | | | Implied Volatility | | | | | | 24% - 83% | | | 17% - 76% | |
(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% - 76% | |
A 10 percent increase or decrease in implied volatility for the WTI options would cause a corresponding $1$7 million ($2 million as at December 31, 2017) increase or decrease to net risk management assets and liabilities.
19. | 19. Financial Instruments and Risk Management
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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. B) Risk Management Activities Encana uses derivative financial instruments to manage its exposure to cash flow variability from commodity prices 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 entered 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, fixed price swaptions and options. Encana has also entered into basis swaps to manage against widening price differentials between various production areas and benchmark price points. 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 March 31,September 30, 2018, Encana has entered into $538$179 million notional U.S. dollar denominated currency swaps at an average exchange rate of US$0.7606 to C$1, which mature monthly through the remainder of 2018.2018 and $350 million notional U.S. dollar denominated currency swaps at an average exchange rate of US$0.7579 to C$1, which mature monthly throughout 2019.
Risk Management Positions as at March 31,September 30, 2018 | | | | | | | | | | Notional Volumes | | Term | | Average Price | | | Fair Value | | | | Notional Volumes | | | Term | | | Average Price | | Fair Value | | | | | | | | | | | | | | Crude Oil and NGL Contracts | | | | | | US$/bbl | | | | | | | | US$/bbl | | | | | | Fixed Price Contracts | | | | | | | | | | | | | | | | | | | | | WTI Fixed Price | | | 94.3 Mbbls/d | | | | 2018 | | | 55.53 | | $ | (194 | ) | | 110.5 Mbbls/d | | 2018 | | | 55.65 | | | $ | (175 | ) | WTI Fixed Price | | | 15.0 Mbbls/d | | | | 2019 | | | 58.30 | | | (2 | ) | | 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 | | | 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 | | | | (1 | ) | | | | | | | | | | | | | | | WTI Fixed Price Swaptions(1) | | | 24.0 Mbbls/d | | | | Q1 - Q2 2019 | | | 63.13 | | | (16 | ) | | 24.0 Mbbls/d | | Q1 - Q2 2019 | | | 63.13 | | | | (42 | ) | | | | | | | | | | | | | | | WTIThree-Way Options | | | | | | | | | | | | | | | | | | | | | Sold call / bought put / sold put | | | 16.0 Mbbls/d | | | | 2018 | | | 54.49 / 47.17 / 36.88 | | | (42 | ) | | 16.0 Mbbls/d | | 2018 | | 54.49 / 47.17 / 36.88 | | | | (25 | ) | Sold call / bought put / sold put | | | 52.5 Mbbls/d | | 2019 | | 69.22 / 59.47 / 48.57 | | | | (110 | ) | | | | | | | | | | | | | | | WTI Costless Collars | | | | | | | | | | | | | | | | | | | | | Sold call / bought put | | | 10.0 Mbbls/d | | | | 2018 | | | 57.08 / 45.00 | | | (20 | ) | | 10.0 Mbbls/d | | 2018 | | 57.08 / 45.00 | | | | (13 | ) | | | | | | | | | | | | | | | Basis Contracts(2) | | | | | 2018 - 2020 | | | | | | 26 | | | | | 2018 | | | | | | | 15 | | | | | | | 2019 | | | | | | | 27 | | | | | | | 2020 | | | | | | | (4 | ) | | | | | | | | | | | | | | | Crude Oil and NGLs Fair Value Position | | | | | | | | | (248 | ) | | | | | | | | | | | (491 | ) | | | | | | | | | | | | | | | | | Natural Gas Contracts | | | | | | US$/Mcf | | | | | | | | US$/Mcf | | | | | | | Fixed Price Contracts | | | | | | | | | | | | | | | | | | | | | NYMEX Fixed Price | | | 1,017 MMcf/d | | 2018 | | | 3.03 | | | | (1 | ) | NYMEX Fixed Price | | | 1,007 MMcf/d | | | | 2018 | | | 3.02 | | | 52 | | | 742 MMcf/d | | 2019 | | | 2.73 | | | | (13 | ) | | | | | | | | | | | | | | | | | NYMEX Fixed Price Swaptions(3) | | | 300 MMcf/d | | | | Q1 - Q2 2019 | | | 2.99 | | | (9 | ) | | 300 MMcf/d | | Q1 - Q2 2019 | | | 2.99 | | | | (7 | ) | | | | | | | | | | | | | | | | | NYMEX Call Options | | | | | | | | | | | | | | | | | | | | | Sold call price | | | 230 MMcf/d | | | | 2018 | | | 3.75 | | | (1 | ) | | 230 MMcf/d | | 2018 | | | 3.75 | | | | - | | Sold call price | | | 64 MMcf/d | | | | 2019 | | | 3.75 | | | (4 | ) | | 230 MMcf/d | | 2019 | | | 3.75 | | | | (4 | ) | Bought call price | | | 230 MMcf/d | | 2019 | | | 3.75 | | | | - | | Sold call price | | | 166 MMcf/d | | | | 2020 | | | 3.25 | | | (1 | ) | | 230 MMcf/d | | 2020 | | | 3.25 | | | | 1 | | | | | | | | | | | | | | | | | | Basis Contracts(4) | | | | | 2018 | | | | | | 130 | | | | | 2018 | | | | | | | 35 | | | | | | | 2019 | | | | | | 136 | | | | | 2019 | | | | | | | 126 | | | | | | | 2020 | | | | | | 99 | | | | | 2020 | | | | | | | 88 | | | | | | | 2021 - 2023 | | | | | | 86 | | | | | 2021 - 2023 | | | | | | | 18 | | | | | | | | | | | | | | | | | | Premiums Received on Unexpired Options | | | | | | | | | (3 | ) | | Natural Gas Fair Value Position | | | | | | | | | 485 | | | | | | | | | | | | 243 | | | | | | | | | | | | | | | | | | Net Premiums Received on Unexpired Options | | | | | | | | | | | | (4 | ) | | | | | | | | | | | | | | | Other Derivative Contracts | | | | | | | | | | | | | | | | | | | | | | Fair Value Position | | | | | | | | | (18 | ) | | | | | | | | | | | (15 | ) | | | | | | | | | | | | | | | | | Foreign Currency Contracts | | | | | | | | | | | | | | | | | | | | | | Fair Value Position(5) | | | | | 2018 | | | | | | 12 | | | | | 2018 - 2019 | | | | | | | 12 | | Total Fair Value Position | | | | | | | | $ | 231 | | | Total Fair Value Position and Net Premiums Received | | | | | | | | | | | $ | (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 wideningweakening Midland, Magellan East Houston, Louisiana Light Sweet and Edmonton Condensate differentials to WTI. |
(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 wideningweakening AECO, Dawn, Chicago, Malin and Waha basis to NYMEX. |
(5) | Encana has entered into U.S. dollar denominatedfixed-for-floating average currency swaps to protect against fluctuations between the Canadian and U.S. dollars. |
Earnings Impact of Realized and Unrealized Gains (Losses) on Risk Management Positions | | | Three Months Ended | | | Nine Months Ended | | | | | | | | September 30, | | | September 30, | | | | Three Months Ended March 31, | | | 2018 | | | 2017 | | | 2018 | | | 2017 | | | | 2018 | | | 2017 | | | | | | | | | | | | | | | | | | Realized Gains (Losses) on Risk Management | | | | | | | | | | | | | | | | | | | | | | Commodity and Other Derivatives: | | | | | | | | | | | | | | | | | | | | | | Revenues(1) | | $ | (32 | ) | | $ | (24 | ) | | $ | (77 | ) | | $ | 41 | | | $ | (95 | ) | | $ | 36 | | Transportation and processing | | | - | | | (4 | ) | | | - | | | | - | | | | - | | | | (4 | ) | Foreign Currency Derivatives: | | | | | | | | | | | | | | | | | | | | | | Foreign exchange | | | 7 | | | 1 | | | | 1 | | | | 9 | | | | 11 | | | | 8 | | | | $ | (25 | ) | | $ | (27 | ) | | $ | (76 | ) | | $ | 50 | | | $ | (84 | ) | | $ | 40 | | | | | | | | | | | | | | | | | | | | | Unrealized Gains (Losses) on Risk Management | | | | | | | | | | | | | | | | | | | | | | Commodity and Other Derivatives: | | | | | | | | | | | | | | | | | | | | | | Revenues(2) | | $ | 68 | | | $ | 362 | | | $ | (164 | ) | | $ | (76 | ) | | $ | (422 | ) | | $ | 396 | | Foreign Currency Derivatives: | | | | | | | | | | | | | | | | | | | | | | Foreign exchange | | | (18 | ) | | 2 | | | | 9 | | | | 14 | | | | (17 | ) | | | 40 | | | | $ | 50 | | | $ | 364 | | | $ | (155 | ) | | $ | (62 | ) | | $ | (439 | ) | | $ | 436 | | | | | | | | | | | | | | | | | | | | | Total Realized and Unrealized Gains (Losses) on Risk Management, net | | | | | | | | | | | | | | | | | | | | | | Commodity and Other Derivatives: | | | | | | | | | | | | | | | | | | | | | | Revenues(1) (2) | | $ | 36 | | | $ | 338 | | | $ | (241 | ) | | $ | (35 | ) | | $ | (517 | ) | | $ | 432 | | Transportation and processing | | | - | | | (4 | ) | | | - | | | | - | | | | - | | | | (4 | ) | Foreign Currency Derivatives: | | | | | | | | | | | | | | | | | | | | | | Foreign exchange | | | (11 | ) | | 3 | | | | 10 | | | | 23 | | | | (6 | ) | | | 48 | | | | $ | 25 | | | $ | 337 | | | $ | (231 | ) | | $ | (12 | ) | | $ | (523 | ) | | $ | 476 | |
(1) | Includes a realized gaingains of $1$2 million and $5 million for the three and nine months ended September 30, 2018, respectively, (2017 - gaingains of $2 million)million and $5 million, respectively) related to other derivative contracts. |
(2) | Includes an unrealized gainlosses of nil and $1 million for the three and nine months ended September 30, 2018, respectively, (2017 - nil)losses of nil and $1 million, respectively) related to other derivative contracts. |
Reconciliation of Unrealized Risk Management Positions from January 1 to March 31September 30 | | | 2018 | | | 2017 | | | | | 2018 | | | 2017 | | | | Fair Value | | Total Unrealized Gain (Loss) | | | Total Unrealized Gain (Loss) | | | | | Fair Value | | | Total Unrealized Gain (Loss) | | | Total Unrealized Gain (Loss) | | | | | | | | | | | | | | | | | | | | Fair Value of Contracts, Beginning of Year | | $ | 183 | | | | | | | | | | $ | 183 | | | | | | | | | | Change in Fair Value of Contracts in Place at Beginning of Year and Contracts Entered into During the Period | | | 25 | | | $ | 25 | | | $ | 337 | | | | | | (523 | ) | | $ | (523 | ) | | $ | 476 | | Settlement of Other Derivative Contracts | | | 1 | | | | | | | | | | | 5 | | | | | | | | | | Fair Value of Contracts Realized During the Period | | | 25 | | | | 25 | | | | 27 | | | | | | 84 | | | | 84 | | | | (40 | ) | Fair Value of Contracts Outstanding | | $ | 234 | | | $ | 50 | | | $ | 364 | | | | | $ | (251 | ) | | $ | (439 | ) | | $ | 436 | | Premiums Received on Unexpired Options | | | (3 | ) | | | | | | | Fair Value of Contracts and Premiums Received, End of Period | | $ | 231 | | | | | | | | Net Premiums Received on Unexpired Options | | | | | | (4 | ) | | | | | | | | | Fair Value of Contracts and Net Premiums Received, End of Period | | | | | $ | (255 | ) | | | | | | | | |
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.
Unrealized Risk Management Positions | | | As at | | | As at | | | | | September 30, | | | December 31, | | | | | | | | 2018 | | | 2017 | | | | As at March 31, 2018 | | | As at December 31, 2017 | | | | | | | | | | Risk Management Assets | | | | | | | | | | | | | | Current | | $ | 226 | | | $ | 205 | | | $ | 146 | | | $ | 205 | | Long-term | | | 290 | | | | 246 | | | | 132 | | | | 246 | | | | | 516 | | | | 451 | | | | 278 | | | | 451 | | | | | | | | | | | | | Risk Management Liabilities | | | | | | | | | | | | | | Current | | | 250 | | | | 236 | | | | 450 | | | | 236 | | Long-term | | | 17 | | | | 13 | | | | 68 | | | | 13 | | | | | 267 | | | | 249 | | | | 518 | | | | 249 | | | | | | | | | | | | | Other Derivative Contracts | | | | | | | | | | | | | | Current in accounts payable and accrued liabilities | | | 5 | | | | 5 | | | | 5 | | | | 5 | | Long-term in other liabilities and provisions | | | 13 | | | | 14 | | | | 10 | | | | 14 | | Net Risk Management Assets (Liabilities) and Other Derivative Contracts | | $ | 231 | | | $ | 183 | | | $ | (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 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 March 31,September 30, 2018, the Company had no significant credit derivatives in place and held no collateral. As at March 31,September 30, 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 March 31,September 30, 2018, approximately 9392 percent (92 percent as at December 31, 2017) of Encana’s accounts receivable and financial derivative credit exposures were with investment grade counterparties. As at March 31,September 30, 2018, Encana had two 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 March 31,September 30, 2018, these counterparties accounted for 5369 percent and 11 percent of the fair value of the outstandingin-the-money net risk management contracts. As at December 31, 2017, Encana had three counterparties whose net settlement position accounted for 56 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 three to six years with a fair value recognized of $18$15 million as at March 31,September 30, 2018 ($19 million as at December 31, 2017). The
maximum potential amount of undiscounted future payments is $317$258 million as at March 31,September 30, 2018, and is considered unlikely. 20. | 20. Supplementary Information
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Supplemental disclosures to the Condensed Consolidated Statement of Cash Flows are presented below: A) | Net Change inNon-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 | ) |
| | | | | | | | | | | Three Months Ended March 31, | | | | 2018 | | | 2017 | | | | | Operating Activities | | | | | | | | | Accounts receivable and accrued revenues | | $ | (2 | ) | | $ | 70 | | Accounts payable and accrued liabilities | | | (7 | ) | | | (134 | ) | Income tax receivable and payable | | | 1 | | | | (96 | ) | | | $ | (8 | ) | | $ | (160 | ) |
| | 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 March 31, | | | | 2018 | | | 2017 | | | | | Non-Cash Investing Activities | | | | | | | | | Asset retirement obligation incurred (See Note 12) | | $ | 5 | | | $ | 3 | | Property, plant and equipment accruals | | | 9 | | | | �� 44 | | Capitalized long-term incentives | | | (36 | ) | | | 11 | | Property additions/dispositions (swaps) | | | 49 | | | | 6 | | Non-Cash Financing Activities | | | | | | | | | Common shares issued under dividend reinvestment plan (See Note 13) | | $ | - | | | $ | - | |
21. | 21. Commitments and Contingencies
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Commitments The following table outlines the Company’s commitments as at March 31,September 30, 2018: | | | Expected Future Payments | | | Expected Future Payments | | (undiscounted) | | 2018 | | 2019 | | 2020 | | 2021 | | 2022 | | Thereafter | | Total | | | 2018 | | | 2019 | | | 2020 | | | 2021 | | | 2022 | | | Thereafter | | | Total | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Transportation and Processing | | $ | 446 | | | $ | 692 | | | $ | 663 | | | $ | 579 | | | $ | 551 | | | $ | 2,458 | | | $ | 5,389 | | | $ | 146 | | | $ | 709 | | | $ | 688 | | | $ | 598 | | | $ | 571 | | | $ | 2,763 | | | $ | 5,475 | | Drilling and Field Services | | 165 | | | 46 | | | 24 | | | 9 | | | | - | | | | - | | | | 244 | | | | 73 | | | | 66 | | | | 29 | | | | 9 | | | | - | | | | - | | | | 177 | | Operating Leases | | 13 | | | 16 | | | 16 | | | 15 | | | 15 | | | 46 | | | | 121 | | | | 4 | | | | 17 | | | | 17 | | | | 16 | | | | 16 | | | | 49 | | | | 119 | | Total | | $ | 624 | | | $ | 754 | | | $ | 703 | | | $ | 603 | | | $ | 566 | | | $ | 2,504 | | | $ | 5,754 | | | $ | 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 15. Divestiture transactions can reduce certain commitments disclosed above.
Contingencies 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.
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.
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 March 31,September 30, 2018 (“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, 2017, which are included in Items 8 and 7, respectively, of the 2017 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:
Executive Overview Strategy Encana is a leading North American energy producer that is focused on developing its multi-basin portfolio of oil, NGLs 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 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 2017 Annual Report on Form10-K. In evaluating its operations and assessing its leverage, the Company reviews performance-based measures such asNon-GAAP Cash Flow andNon-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
Highlights During the first quarternine months of 2018, Encana focused on executing its 2018 capital plan, maintaining operational efficiencies achieved in 2017 and minimizing the effect of inflationary costs. Higher revenues in the first nine months of 2018 compared to 2017 resulting from higher liquids benchmark prices and production volumes. Higher oil and NGL benchmark prices during the first quarter of 2018 compared to 2017 contributed to increases in Encana’s average realized oil and NGL prices of 2840 percent and 2135 percent, respectively, resulting in higher revenues.respectively. Liquids production volumes increased by 32 percent compared to 2017. Encana is also focused on the diversification of the Company’s downstream markets to capture higher realized prices. Encana remains committed to delivering 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, 2018 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, 2018 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. | · | | Received approval from the TSX to purchase, for cancellation, up to 35 million common shares pursuant to a NCIB over a12-month period from February 28, 2018 to February 27, 2019. As of March 31, 2018, the Company has purchased 10 million common shares for total consideration of approximately $111 million.
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Financial Results
| · | | Reported net earnings of $151 million, including a net foreign exchange loss of $91 million, before tax, and net gains on risk management in revenues of $36 million, before tax.
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| · | | Generated cash from operating activities of $381 million,Non-GAAP Cash Flow of $400 million andNon-GAAP Cash Flow Margin of $13.70 per BOE.
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| · | | Paid dividends of $0.015 per common share.
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| · | | Held cash and cash equivalents of $433 million and had available credit facilities of $4.0 billion for total liquidity of $4.4 billion at March 31, 2018.
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Capital Investment
| · | | Commenced the Company’s 2018 capital plan with expenditures totaling $508 million of which $393 million, or 77 percent, was directed to the Permian and Montney.
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| · | | 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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Production Three months ended September 30, 2018 | · | | 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, 2018 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 NGL volumes of 145.2 Mbbls/d which accounted for 45 percent of total production volumes. Average oil and plant condensate production volumes of 113.2 Mbbls/d were 78 percent of total liquids production volumes. |
| · | | Produced average natural gas volumes of 1,075 MMcf/d which accounted for 55 percent of total production volumes.
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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 | · | | Focused on maintaining operational efficiencies achieved in previous years and minimizing the effect of inflationary costs.
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| · | | Increased transportation and processing expense by $37 million, or 17 percent, primarily due to higher volumes in Montney and additional costs incurred in conjunction with the diversification of downstream markets to capture higher realized prices.
| 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.On October 1, 2018, OutlookEncana 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.
2018 Outlook Industry Outlook The oil and gas industry is cyclical and commodity prices are inherently volatile. Oil prices duringfor the remainder of 2018 are expected to reflect global supply and demand dynamics as well as the geopolitical environment. At a meetingThe original OPEC agreement implemented in November 2017 OPECto limit output and certainnon-OPEC countries agreed to further extend an agreement to voluntarily cut crude oil production through the end of 2018. The agreement and recent drawdowns of oil storage inventory levels were generally supportive of oil prices in the first quarterhalf of 2018; however, production growth2018. Trade disputes and oil supply outages in otherrecent months resulting from geopolitical instability in major producing countries continues to partially offsethas created additional uncertainty for oil and gas supply which could impact prices for the expected benefitremainder of the year. As well, prices could be impacted as a result of decisions made by OPEC agreement.and certain non-OPEC countries to increase future oil production. OPEC is scheduledand certain non-OPEC countries are expected to meet again in JuneDecember 2018 to review production levels and decide on a decisionframework for permanent cooperation with allied producers to discontinue or reduce the production cutsseek a balanced and sustainable global oil market. The result of this meeting could negatively impact oil pricesfurther contribute to price fluctuations in 2018.2019. Natural gas prices in 2018 will be affected by the timing of supply and demand growth.growth 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. StrongerRelatively strong condensate prices may also lend support to activity levels resulting in additionalcontinued downward pressure on natural gas prices infor the remainder of 2018. Natural gas prices in the U.S. have remained flat. 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 Permian Basin. Company Outlook Encana is positioned to be flexible in the current price environment in order to continue to achieve strong returns. The Company enters into derivative financial instruments which 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 at March 31,September 30, 2018, the Company has hedged approximately 120137 Mbbls/d of expected oil and condensate production and 1,0261,017 MMcf/d of expected natural gas production for the remainder of 2018 using a varietythe 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 structures at average prices of $55.52 per bbl and $3.02 per Mcf, respectively.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, naturalthe 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.
Capital Investment Encana is on track to meet its updated full year capital investment guidance of $1.8 billion to $1.9approximately $2.0 billion. During the first quarternine months of 2018, the Company spent $508 million,$1.6 billion, of which $238$718 million was directed to Permian where the Company has drilled 2681 net wells and $155$445 million was directed to Montney with 40108 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 expected to be 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. Encana’sEncana's large-scale cube development model utilizes multi-well pads and advanced completion designs to access stacked pay resource to maximize returns and resource recovery from its 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 the recent years, thereby reducing the extent of exposure to market volatility of a particular commodity. During the first quarternine months of 2018, average liquids production volumes were 145.2159.9 Mbbls/d and average natural gas production volumes were 1,0751,123 MMcf/d. The Company expects to deliver substantial liquids growth infor the second halfremainder of 2018.the year. The Company is on track to meet the full year 2018 guidance ranges for liquids production volumes of 165.0 Mbbls/d to 175.0 Mbbls/d and natural gas production volumes of 1,150 MMcf/d to 1,250 MMcf/d by year end as a result of the Company’s growth plans for Montney. Encana’s growth plans for Montney are supported by third party processing plants commissioned in 2017 and two additional facilities expected to be completed in the second halfquarter of 2018, includingas well as the planned completion of the Pipestone liquids hub inat the fourthend 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 operational 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 quarternine months of 2018 are on track to meet the full year updated 2018 guidance ranges. Transportation and processing expense was $7.42$7.39 per BOE, while upstream operating expense and administrative expense, excluding long-term incentive costs, were $3.60$3.35 per BOE and $1.49$1.34 per BOE, respectively. Service costs are expected to increase with higher activity in the oil and gas industry and the recovery of commodityliquids prices. Encana continuesstrives to offset any inflationary pressures with efficiency improvements and effective supply chain management, including favorable price negotiations. Further information on Encana’s 2018 Corporate Guidance can be accessed on the Company’s website at
www.encana.comResults of .Operations
Selected Financial Information | | | Three months ended September 30, | | | | | Nine months ended September 30, | | ($ 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 March 31, | ($ millions) | | | 2018 | | | | | 2017 (1) | Product and Service Revenues | | | | | | | | | Upstream product revenues | | $ | 957 | | | $ | | 738 | Market optimization | | | 301 | | | | | 186 | Service revenues | | | 2 | | | | | 10 | Total Product and Service Revenues | | | 1,260 | | | | | 934 | Gains (Losses) on Risk Management, Net | | | 36 | | | | | 338 | Sublease Revenues | | | 17 | | | | | 17 | Total Revenues | | | 1,313 | | | | | 1,289 | | | | | Total Operating Expenses(2) | | | 976 | | | | | 800 | Operating Income (Loss) | | | 337 | | | | | 489 | Total Other (Income) Expenses | | | 177 | | | | | 55 | Net Earnings (Loss) Before Income Tax | | $ | 160 | | | $ | | 434 | | | | | Net Earnings (Loss) | | $ | 151 | | | $ | | 431 | (1) Corporate interest income of $8 million previously reported in revenues and operating income (loss) in Q1 2017 has been reclassified to other (gains) losses, net. The remaining Q1 2017 revenues have been realigned to conform with the current year presentation. (2) Total Operating Expenses includenon-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, NGLs 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 linked to Edmonton Condensate and AECO, as well as other downstream natural gas benchmarks, including Dawn, which reflect the diversification of the Company’s markets.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 March 31, | (average for the period) | | 2018 | | 2017 | | | | Oil & NGLs | | | | | | | | | WTI ($/bbl) | | $ | 62.87 | | | $ | 51.91 | | Edmonton Condensate (C$/bbl) | | | 79.72 | | | | 69.13 | | | | | Natural Gas | | | | | | | | | NYMEX ($/MMBtu) | | $ | 3.00 | | | $ | 3.32 | | AECO (C$/Mcf) | | | 1.85 | | | | 2.94 | | Dawn (C$/MMBtu) | | | 3.82 | | | | 4.23 | |
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 | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | Production Volumes (1) | | | | Realized Prices (2) | Three months ended March 31, | | 2018 | | 2017 | | | | 2018 | | 2017 | | | | | | | Oil(Mbbls/d, $/bbl) | | | | | | | | | | | | | | | | | | | | | | | | | | Canadian Operations | | | | 0.4 | | | | | 0.4 | | | | | | | | | $ | 55.47 | | | | $ | 43.29 | | USA Operations | | | | 82.6 | | | | | 67.0 | | | | | | | | | | 63.33 | | | | | 49.65 | | Total | | | | 83.0 | | | | | 67.4 | | | | | | | | | | 63.29 | | | | | 49.61 | | | | | | | | NGLs – Plant Condensate(Mbbls/d, $/bbl) | | | | | | | | | | | | | | | | | | | | | | | | | | Canadian Operations | | | | 27.5 | | | | | 18.7 | | | | | | | | | | 61.10 | | | | | 50.29 | | USA Operations | | | | 2.7 | | | | | 1.8 | | | | | | | | | | 51.94 | | | | | 42.87 | | Total | | | | 30.2 | | | | | 20.5 | | | | | | | | | | 60.28 | | | | | 49.63 | | | | | | | | NGLs – Other(Mbbls/d, $/bbl) | | | | | | | | | | | | | | | | | | | | | | | | | | Canadian Operations | | | | 10.4 | | | | | 5.0 | | | | | | | | | | 30.08 | | | | | 22.62 | | USA Operations | | | | 21.6 | | | | | 18.0 | | | | | | | | | | 20.53 | | | | | 20.11 | | Total | | | | 32.0 | | | | | 23.0 | | | | | | | | | | 23.64 | | | | | 20.66 | | | | | | | | Total NGLs(Mbbls/d, $/bbl) | | | | | | | | | | | | | | | | | | | | | | | | | | Canadian Operations | | | | 37.9 | | | | | 23.7 | | | | | | | | | | 52.55 | | | | | 44.40 | | USA Operations | | | | 24.3 | | | | | 19.8 | | | | | | | | | | 24.01 | | | | | 22.22 | | Total | | | | 62.2 | | | | | 43.5 | | | | | | | | | | 41.40 | | | | | 34.31 | | | | | | | | Total Oil & NGLs(Mbbls/d, $/bbl) | | | | | | | | | | | | | | | | | | | | | | | | | | Canadian Operations | | | | 38.3 | | | | | 24.1 | | | | | | | | | | 52.58 | | | | | 44.38 | | USA Operations | | | | 106.9 | | | | | 86.8 | | | | | | | | | | 54.39 | | | | | 43.36 | | Total | | | | 145.2 | | | | | 110.9 | | | | | | | | | | 53.91 | | | | | 43.59 | | | | | | | | Natural Gas(MMcf/d, $/Mcf) | | | | | | | | | | | | | | | | | | | | | | | | | | Canadian Operations | | | | 936 | | | | | 885 | | | | | | | | | | 2.48 | | | | | 2.52 | | USA Operations | | | | 139 | | | | | 356 | | | | | | | | | | 2.52 | | | | | 3.23 | | Total | | | | 1,075 | | | | | 1,241 | | | | | | | | | | 2.48 | | | | | 2.72 | | | | | | | | Total Production(MBOE/d, $/BOE) | | | | | | | | | | | | | | | | | | | | | | | | | | Canadian Operations | | | | 194.3 | | | | | 171.7 | | | | | | | | | | 22.29 | | | | | 19.23 | | USA Operations | | | | 130.1 | | | | | 146.2 | | | | | | | | | | 47.39 | | | | | 33.59 | | Total | | | | 324.4 | | | | | 317.9 | | | | | | | | | | 32.35 | | | | | 25.82 | | | | | | | | Production Mix (%) | | | | | | | | | | | | | | | | | | | | | | | | | | Oil & Plant Condensate | | | | 35 | | | | | 28 | | | | | | | | | | | | | | | | | NGLs – Other | | | | 10 | | | | | 7 | | | | | | | | | | | | | | | | | Total Oil & NGLs | | | | 45 | | | | | 35 | | | | | | | | | | | | | | | | | Natural Gas | | | | 55 | | | | | 65 | | | | | | | | | | | | | | | | | | | | | | | Core Assets Production | | | | | | | | | | | | | | | | | | | | | | | | | | Oil (Mbbls/d) | | | | 80.4 | | | | | 62.3 | | | | | | | | | | | | | | | | | | | | | | | NGLs – Plant Condensate (Mbbls/d) | | | | 30.2 | | | | | 20.0 | | | | | | | | | | | | | | | | | NGLs – Other (Mbbls/d) | | | | 30.9 | | | | | 20.9 | | | | | | | | | | | | | | | | | Total NGLs (Mbbls/d) | | | | 61.1 | | | | | 40.9 | | | | | | | | | | | | | | | | | | | | | | | Total Oil & NGLs (Mbbls/d) | | | | 141.5 | | | | | 103.2 | | | | | | | | | | | | | | | | | | | | | | | Natural Gas (MMcf/d) | | | | 996 | | | | | 804 | | | | | | | | | | | | | | | | | | | | | | | Total Production (MBOE/d) | | | | 307.5 | | | | | 237.3 | | | | | | | | | | | | | | | | | | | | | | | % of Total Encana Production | | | | 95 | | | | | 75 | | | | | | | | | | | | | | | | | (1) Average daily. (2) Averageper-unit prices, excluding the impact of risk management activities. | | | | | | | | | | | | | | | | | | | | | |
(2) | Average per-unit prices, excluding the impact of risk management activities. |
Upstream Product Revenues | | | Three months ended March 31, | | Three months ended September 30, | | | Nine months ended September 30, | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ($ millions) | | Oil | | NGLs(1) | | Natural Gas(2) | | Total | | Oil | | | NGLs (1) | | | Natural Gas (2) | | | Total | | | Oil | | | NGLs (1) | | | Natural Gas (2) | | | Total | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2017 Upstream Product Revenues | | | $ | 300 | | | | $ | 134 | | | | $ | 304 | | | $ | 738 | | | $ | 317 | | | $ | 156 | | | $ | 173 | | | $ | 646 | | | $ | 942 | | | $ | 425 | | | $ | 745 | | | $ | 2,112 | | Increase (decrease) due to: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Sales prices | | | 102 | | | | 32 | | | | (5 | ) | | 129 | | | | 184 | | | | 92 | | | | 10 | | | | 286 | | | | 445 | | | | 195 | | | | (59 | ) | | | 581 | | Production volumes | | | 72 | | | | 65 | | | | (58 | ) | | 79 | | | | 86 | | | | 106 | | | | 36 | | | | 228 | | | | 185 | | | | 248 | | | | (39 | ) | | | 394 | | 2018 Upstream Product Revenues | | | $ | 474 | | | | $ | 231 | | | | $ | 241 | | | $ | 946 | | | $ | 587 | | | $ | 354 | | | $ | 219 | | | $ | 1,160 | | | $ | 1,572 | | | $ | 868 | | | $ | 647 | | | $ | 3,087 | | (1) Includes plant condensate. (2) Natural gas revenues exclude a royalty adjustment of $11 million (2017 - nil) with no associated production volumes. | | |
(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 March 31,September 30, 2018 versus March 31,September 30, 2017 Oil revenues increased $174$270 million compared to the firstthird quarter of 2017 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 realized oil prices of $13.68 per bbl, or 28 percent, increased revenues by $102 million. The increase reflected a higher WTI benchmark price which was up 21 percent. The increase was also due to improved regional pricing in the USA Operations; and
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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). | · | | Higher average oil production volumes of 15.6 Mbbls/d increased revenues by $72 million. Higher volumes were primarily due to a successful drilling program in Permian (18.9 Mbbls/d), partially offset by asset sales (2.4 Mbbls/d), which mainly include the Tuscaloosa Marine Shale assets in the second quarter of 2017.
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NGL Revenues
ThreeNine months ended March 31,September 30, 2018 versus March 31,September 30, 2017
NGLOil revenues increased $97$630 million compared to the first nine months of 2017 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 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 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. NGL Revenues Three months ended September 30, 2018 versus September 30, 2017 NGL revenues increased $198 million compared to the third quarter of 2017 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). | · | | Higher average realized NGL prices of $7.09 per bbl, or 21 percent, increased revenues by $32 million. The increase reflected higher Edmonton Condensate and WTI benchmark prices which were up 15 percent and 21 percent, respectively, as well as improved regional pricing; and
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| · | | Higher average NGL production volumes of 18.7 Mbbls/d increased revenues by $65 million. Higher volumes were primarily due to successful drilling programs in Montney and Permian (21.0 Mbbls/d), partially offset by asset sales (1.6 Mbbls/d), which mainly include the Piceance natural gas assets in the third quarter of 2017.
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Natural Gas Revenues
ThreeNine months ended March 31,September 30, 2018 versus March 31,September 30, 2017
Natural gasNGL revenues decreased $63increased $443 million compared to the first quarternine months of 2017 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 | · | | Lower average realized natural gas prices of $0.24 per Mcf, or nine percent, decreased revenues by $5 million. The decrease reflected lower NYMEX and AECO benchmark prices which were down 10 percent and 37 percent, respectively, partially offset by relatively higher other downstream benchmark prices in 2018 resulting from the diversification of the Company’s markets; and
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| · | | Lower average natural gas production volumes of 166 MMcf/d decreased revenues by $58 million. Lower volumes were primarily due to asset sales (305 MMcf/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 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.
Natural Gas Revenues Three months ended September 30, 2018 versus September 30, 2017 Natural gas revenues increased $46 million compared to the third quarter of 2017 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 | • | Production volume changes decreased revenues by $39 million resulting from: |
| o | Lower production volumes in the USA Operations (158 MMcf/d) decreased revenues by $134 million primarily due to the sale of the Piceance natural gas assets in the third quarter of 2017 (173 MMcf/d), partially offset by a successful drilling program in Permian in 2018 (25 MMcf/d). |
| o | Higher production volumes in Canadian Operations (173 MMcf/d) increased revenues by $95 million resulting from a successful drilling program in Montney (242 MMcf/d) and decreased downtime resulting from scheduled plant maintenance in Montney in 2017 (27 MMcf/d), partially offset by asset sales (66 MMcf/d), which mainly include certain assets in Wheatland in the fourth quarter of 2017, and lower activityvolumes in Other Upstream Operations (74 MMcf/d), partially offset by successful drilling in Montney and Permian (199(30 MMcf/d). |
Gains (Losses) on Risk Management, Net As a means of managing commodity price volatility, Encana enters into commodity derivative financial instruments on a portion of its expected oil, NGLsNGL and natural gas production volumes. The Company’s commodity price mitigation program reduces volatility and helps sustain revenues during periods of lower prices. Further information on the Company’s
commodity price positions as at March 31,September 30, 2018 can be found in Note 19 to the Consolidated Financial Statements included in Part I, Item 1 of this Quarterly Report on Form10-Q. The following table providestables provide the effects of Encana’s risk management activities on revenues. | | | | | | | | | | | | | Three months ended September 30, | | | | Nine months ended September 30, | | | | $ millions | | | | | | Per-Unit | | Three months ended March 31, | | 2018 | | | 2017 | | | | | | 2018 | | | 2017 | | ($ millions) | | | | 2018 | | | 2017 | | | | 2018 | | | 2017 | | | | | | | | | | | | | | | | | | | | | | | | | Realized Gains (Losses) on Risk Management | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Commodity Price | | | | | | | | | | | | Oil ($/bbl) | | $ | (56) | | | $ | - | | | | | $ | (7.55) | | | $ 0.05 | | NGLs ($/bbl)(1) | | | (21) | | | | (1) | | | | | $ | (3.77) | | | $ (0.42) | | Natural Gas ($/Mcf) | | | 44 | | | | (25) | | | | | $ | 0.46 | | | $ (0.22) | | Other(2) | | | 1 | | | | 2 | | | | | $ | - | | | $ - | | Total ($/BOE) | | | (32) | | | | (24) | | | | | $ | (1.13) | | | $ (0.91) | | Commodity Price (1) | | | | | | | | | | | | | | | | | | | | Oil | | | | $ | (87 | ) | | $ | 14 | | | | $ | (208 | ) | | $ | 30 | | NGLs (2) | | | | | (47 | ) | | | 4 | | | | | (105 | ) | | | 5 | | Natural Gas | | | | | 56 | | | | 21 | | | | | 216 | | | | (4 | ) | Other (3) | | | | | 1 | | | | 2 | | | | | 2 | | | | 5 | | Total | | | | | (77 | ) | | | 41 | | | | | (95 | ) | | | 36 | | | | | | | | | | | | | | | | | | | | | | | | Unrealized Gains (Losses) on Risk Management | | | 68 | | | | 362 | | | | | | | | | | | (164 | ) | | | (76 | ) | | | | (422 | ) | | | 396 | | Total Gains (Losses) on Risk Management, Net | | $ | 36 | | | $ | 338 | | | | | | | | | | $ | (241 | ) | | $ | (35 | ) | | | $ | (517 | ) | | $ | 432 | | (1) Includes plant condensate. (2) Other includes realized gains or losses from other derivative contracts with no associated production volumes. | | | | | | | | | | | | | | | | | | | | | | | | | | Three months ended September 30, | | | | Nine months ended September 30, | | (Per-unit) | | | | 2018 | | | 2017 | | | | 2018 | | | 2017 | | | | | | | | | | | | | | | | | | | | | | Realized Gains (Losses) on Risk Management | | | | | | | | | | | | | | | | | | | | Commodity Price (1) | | | | | | | | | | | | | | | | | | | | Oil ($/bbl) | | | | $ | (9.77 | ) | | $ | 2.12 | | | | $ | (8.68 | ) | | $ | 1.51 | | NGLs ($/bbl) (2) | | | | $ | (6.21 | ) | | $ | 0.58 | | | | $ | (5.32 | ) | | $ | 0.33 | | Natural Gas ($/Mcf) | | | | $ | 0.51 | | | $ | 0.25 | | | | $ | 0.70 | | | $ | (0.01 | ) | Total ($/BOE) | | | | $ | (2.23 | ) | | $ | 1.50 | | | | $ | (1.02 | ) | | $ | 0.37 | |
(1) | Includes realized gains and losses related to the Canadian and USA Operations. |
(2) | Includes plant condensate. |
(3) | Other primarily includes realized gains or losses from Market Optimization and other derivative contracts with no associated production volumes. |
Encana recognizes fair value changes from its risk management activities each reporting period. The changes in fair value result from new positions and settlements that occur during each period, as well as the relationship between contract prices and the associated forward curves. Realized gains or losses on risk management activities related to commodity price mitigation are included in the Canadian Operations, USA Operations and Market Optimization revenues as the contracts are cash settled.settled. Unrealized gains or losses on fair value changes of unsettled contracts are included in the Corporate and Other segment. Market Optimization Revenues Market Optimization revenues relate to activities that provide operational flexibility and cost mitigation for transportation commitments, product type, delivery points and customer diversification. | | | Three months ended March 31, | | Three months ended September 30, | | | Nine months ended September 30, | | ($ millions) | | 2018 | | | 2017 | | 2018 | | | | 2017 | | | 2018 | | | | 2017 | | | | | | | | | | | | | | | | | | | | | | Market Optimization | | $ | 301 | | | $ | 186 | | $ | 317 | | | | $ | 224 | | | $ | 909 | | | | $ | 614 | |
Three months ended March 31,September 30, 2018 versus March 31,September 30, 2017 Market Optimization revenues increased $115$93 million compared to the firstthird quarter of 2017 primarily due to: Higher sales of third-party purchased volumes, primarily related to natural gas, used for optimization activities and long-term marketing arrangements associated with the Company’s previous divestitures ($137 million), partially offset by lower natural gas benchmark prices ($44 million). | · | | Higher sales of third-party purchased volumes, primarily related to natural gas, used for optimization activities and long-term marketing arrangements associated with the Company’s previous divestitures ($168 million), partially offset by lower natural gas commodity prices ($53 million).
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Nine months ended September 30, 2018 versus September 30, 2017 Market Optimization revenues increased $295 million compared to the first nine months of 2017 primarily due to: Higher sales of third-party purchased volumes, primarily related to natural gas, used for optimization activities and long-term marketing arrangements associated with the Company’s previous divestitures ($472 million), partially offset by lower natural gas benchmark prices ($177 million). Sublease Revenues Sublease revenues primarily include amounts related to the sublease of office space in The Bow office building recorded in the Corporate and Other segment. Further information on The Bow office sublease can be found in Note 11 to the Consolidated Financial Statements included in Part I, Item 1 of this Quarterly Report on Form10-Q. Operating Expenses Production, Mineral and Other Taxes Production, mineral and other taxes include production and property taxes. Production taxes are generally assessed as a percentage of oil and natural gas production revenues. Property taxes are generally assessed based on the value of the underlying assets. | | | | | | | | | | | | | Three months ended September 30, | | | | Nine months ended September 30, | | ($ millions) | | | | 2018 | | | 2017 | | | | 2018 | | | 2017 | | | | $ millions | | | | | | $/BOE | | | | | | | | | | | | | | | | | | | | Three months ended March 31, | | 2018 | | 2017 | | | | | | 2018 | | 2017 | | | Canadian Operations | | $ | 4 | | | $ | 5 | | | | | | $ | 0.23 | | | $ | 0.30 | | | | $ | 4 | | | $ | 6 | | | | $ | 12 | | | $ | 16 | | USA Operations | | | 25 | | | 24 | | | | | $ | 2.12 | | | $ | 1.84 | | | | | 41 | | | | 21 | | | | | 97 | | | | 64 | | Total | | $ | 29 | | | $ | 29 | | | | | $ | 0.99 | | | $ | 1.01 | | | | $ | 45 | | | $ | 27 | | | | $ | 109 | | | $ | 80 | | | | | | | | | | | | | | | | | | | | | | | | | | Three months ended September 30, | | | | Nine months ended September 30, | | ($/BOE) | | | | 2018 | | | 2017 | | | | 2018 | | | 2017 | | | | | | | | | | | | | | | | | | | | | | Canadian Operations | | | | $ | 0.20 | | | $ | 0.42 | | | | $ | 0.22 | | | $ | 0.37 | | USA Operations | | | | $ | 2.91 | | | $ | 1.69 | | | | $ | 2.53 | | | $ | 1.59 | | Total | | | | $ | 1.31 | | | $ | 1.01 | | | | $ | 1.15 | | | $ | 0.95 | |
Three months ended March 31,September 30, 2018 versus March 31,September 30, 2017 Production, mineral and other taxes were flatincreased $18 million compared to the firstthird quarter of 2017 primarily due to: Higher liquids prices in Permian and Eagle Ford and higher production volumes in Permian ($19 million) and lower production taxes in 2017 from tax recoveries in the USA Operations ($4 million); | · | | Higher oil prices and production volumes in Permian ($7 million);
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partially offset by:by: Asset sales ($3 million), which mainly include certain assets in Wheatland in the fourth quarter of 2017 and the Piceance natural gas assets in the third quarter of 2017 and lower natural gas prices ($2 million). Nine months ended September 30, 2018 versus September 30, 2017 Production, mineral and other taxes increased $29 million compared to the first nine months of 2017 primarily due to: Higher liquids prices in Permian and Eagle Ford and higher production volumes in Permian ($36 million) and lower production taxes in 2017 from tax recoveries in the USA Operations ($6 million); partially offset by: Asset sales ($14 million), which mainly include certain assets in Wheatland in the fourth quarter of 2017 and the Piceance natural gas assets in the third quarter of 2017. | · | | Asset sales ($6 million), 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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Transportation and Processing Transportation and processing expense includes transportation costs incurred to move product from production points to sales points including gathering, compression, pipeline tariffs, trucking and storage costs. Encana also incurs costs related to processing provided by third parties or through ownership interests in processing facilities to bring raw production to sales-qualitysales- quality product. | | | | | | | | | | | | | Three months ended September 30, | | | | Nine months ended September 30, | | | | $ millions | | | | | | $/BOE | | | Three months ended March 31, | | 2018 | | 2017 | | | | | | 2018 | | 2017 | | | ($ millions) | | | | 2018 | | | 2017 | | | | 2018 | | | 2017 | | | | | | | | | | | | | | | | | | | | | | | | | Canadian Operations | | $ | 190 | | | $ | 132 | | | | | $ | 10.87 | | | $ | 8.56 | | | | $ | 211 | | | $ | 138 | | | | $ | 608 | | | $ | 403 | | USA Operations | | | 27 | | | 59 | | | | | | $ | 2.26 | | | $ | 4.44 | | | | | 34 | | | | 31 | | | | | 92 | | | | 141 | | Upstream Transportation and Processing | | | 217 | | | 191 | | | | | $ | 7.42 | | | $ | 6.67 | | | | | 245 | | | | 169 | | | | | 700 | | | | 544 | | | | | | | | | | | | | | | | | | | | | | | Market Optimization | | | 32 | | | 21 | | | | | | | | | | | 33 | | | | 30 | | | | | 99 | | | | 73 | | Corporate and Other | | | - | | | | - | | | | | | | | | Total | | $ | 249 | | | $ | 212 | | | | | | | | | | $ | 278 | | | $ | 199 | | | | $ | 799 | | | $ | 617 | | | | | | | | | | | | | | | | | | | | | | | | | | Three months ended September 30, | | | | Nine months ended September 30, | | ($/BOE) | | | | 2018 | | | 2017 | | | | 2018 | | | 2017 | | | | | | | | | | | | | | | | | | | | | | Canadian Operations | | | | $ | 10.26 | | | $ | 10.00 | | | | $ | 10.78 | | | $ | 9.26 | | USA Operations | | | | $ | 2.38 | | | $ | 2.55 | | | | $ | 2.39 | | | $ | 3.53 | | Upstream Transportation and Processing | | | | $ | 7.05 | | | $ | 6.50 | | | | $ | 7.39 | | | $ | 6.52 | |
Three months ended March 31,September 30, 2018 versus March 31,September 30, 2017 Transportation and processing expense increased $79 million compared to the third quarter of 2017 primarily due to: Higher volumes and gathering and processing fees in Montney and Permian ($51 million), higher downstream processing and transportation costs due to higher volumes primarily in Montney and Permian and costs relating to the diversification of the Company’s downstream markets ($48 million); partially offset by: Asset sales ($11 million), which mainly include the Piceance natural gas assets in the third quarter of 2017and certain assets in Wheatland in the fourth quarter of 2017 and the lower U.S./Canadian dollar exchange rate ($6 million). Nine months ended September 30, 2018 versus September 30, 2017 Transportation and processing expense increased $37$182 million compared to the first quarternine months of 2017 primarily due to: Higher volumes and gathering and processing fees in Montney and Permian ($125 million), higher downstream processing and transportation costs due to higher volumes primarily in Montney and Permian and costs relating to the diversification of the Company’s downstream markets ($139 million) and the higher U.S./Canadian dollar exchange rate ($6 million); | · | | Higher downstream processing and transportation costs mainly in Montney and Duvernay due to Encana’s focus on liquids rich wells in the plays and costs relating to the diversification of the Company’s downstream markets ($39 million), higher volumes and gathering and processing fees in Montney ($28 million), higher volumes in Permian ($6 million) and the higher U.S./Canadian dollar exchange rate ($6 million);
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partially offset by: Asset sales ($71 million), 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 and lower volumes in Other Upstream Operations ($16 million).
| · | | Asset sales ($30 million), which mainly include the Piceance natural gas assets in the third quarter of 2017 and lower activity in Other Upstream Operations ($10 million).
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Operating Operating expense includes costs paid by Encana, net of amounts capitalized, to operate oil and gas properties in which the Company has a working interest. These costs primarily include labour, service contract fees, chemicals and fuel. | | | | | | | | | | | | | Three months ended September 30, | | | | Nine months ended September 30, | | ($ millions) | | | | 2018 | | | 2017 | | | | 2018 | | | 2017 | | | | $ millions | | | | | | $/BOE | | | | | | | | | | | | | | | | | | | | Three months ended March 31, | | 2018 | | 2017 | | | | | | 2018 | | 2017 | | | Canadian Operations | | $ | 29 | | | $ | 31 | | | | | $ | 1.59 | | | $ | 1.91 | | | | $ | 34 | | | $ | 36 | | | | $ | 98 | | | $ | 89 | | USA Operations | | | 74 | | | 87 | | | | | | $ | 6.28 | | | $ | 6.43 | | | | | 80 | | | | 81 | | | | | 238 | | | | 252 | | Upstream Operating Expense(1) | | | 103 | | | 118 | | | | | $ | 3.47 | | | $ | 3.99 | | | | | 114 | | | | 117 | | | | | 336 | | | | 341 | | | | | | | | | | | | | | | | | | | | | | Market Optimization | | | 4 | | | 9 | | | | | | | | | | | 8 | | | | 11 | | | | | 25 | | | | 23 | | Corporate and Other | | | 4 | | | 5 | | | | | | | | | Corporate & Other | | | | | 2 | | | | 4 | | | | | 11 | | | | 13 | | Total | | $ | 111 | | | $ | 132 | | | | | | | | | | $ | 124 | | | $ | 132 | | | | $ | 372 | | | $ | 377 | | | | | | | | | | | | | | | | | | | | | | | | | | Three months ended September 30, | | | | Nine months ended September 30, | | ($/BOE) | | | | 2018 | | | 2017 | | | | 2018 | | | 2017 | | | | | | | | | | | | | | | | | | | | | | Canadian Operations | | | | $ | 1.61 | | | $ | 2.50 | | | | $ | 1.70 | | | $ | 1.97 | | USA Operations | | | | $ | 5.56 | | | $ | 6.57 | | | | $ | 6.16 | | | $ | 6.17 | | Upstream Operating Expense (1) | | | | $ | 3.22 | | | $ | 4.41 | | | | $ | 3.51 | | | $ | 3.98 | |
(1) | (1) | Upstream Operating Expense per BOE for the third quarter and first quarternine months of 2018 includes a recovery of long-term incentive costs of $0.13/$0.15/BOE and $0.16/BOE, respectively (2017 - long-term incentive costs of $0.17/BOE)$0.45/BOE and $0.13/BOE, respectively). |
Three months ended March 31,September 30, 2018 versus March 31,September 30, 2017 Operating expense decreased $21$8 million compared to the firstthird quarter of 2017 primarily due to: Lower long-term incentive costs in 2018 resulting from the smaller change in Encana’s share price in the third quarter of 2018 compared to 2017 ($10 million) and asset sales ($8 million), 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; | · | | Asset sales ($24 million), 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, and a recovery of long-term incentive costs resulting from the decrease in Encana’s share price in the first quarter of 2018 ($14 million). Further information on Encana’s long-term incentives can be found in Note 16 to the Consolidated Financial Statements included in Part I, Item 1 of this Quarterly Report on Form10-Q.
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partially offset by: Higher activity in Montney and Permian ($13 million). Nine months ended September 30, 2018 versus September 30, 2017 Operating expense decreased $5 million compared to the first nine months of 2017 primarily due to: Asset sales ($43 million), 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; partially offset by: Higher activity in Montney and Permian ($35 million) and higher long-term incentive costs resulting from the increase in Encana’s share price in the first nine months of 2018 ($6 million). Further information on Encana’s long-term incentives can be found in Note 16 to the Consolidated Financial Statements included in Part I, Item 1 of this Quarterly Report on Form 10-Q.
| · | | Higher activity in Permian and Montney ($12 million).
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Purchased Product Purchased product expense includes purchases of oil, NGLs and natural gas from third parties that are used to provide operational flexibility and cost mitigation for transportation commitments, product type, delivery points and customer diversification. | | | Three months ended March 31, | | Three months ended September 30, | | | | Nine months ended September 30, | | ($ millions) | | 2018 | | 2017 | | 2018 | | | | 2017 | | | | 2018 | | | | 2017 | | | | | | | | | | | | | | | | | | | | | | | | Market Optimization | | $ | 273 | | | $ | 171 | | $ | 282 | | | | $ | 202 | | | | $ | 803 | | | | $ | 565 | | |
Three months ended March 31,September 30, 2018 versus March 31,September 30, 2017 Purchased product expense increased $102$80 million compared to the firstthird quarter of 2017 primarily due to: Higher third-party volumes purchased, primarily related to natural gas, for optimization activities and long-term marketing arrangements associated with the Company’s previous divestitures ($131 million), partially offset by lower natural gas benchmark prices ($51 million). | · | | Nine months ended September 30, 2018 versus September 30, 2017 Purchased product expense increased $238 million compared to the first nine months of 2017 primarily due to: Higher third-party volumes purchased, primarily related to natural gas, for optimization activities and long-term marketing arrangements associated with the Company’s previous divestitures ($444 million), partially offset by lower natural gas benchmark prices ($206 million). Higher third-party volumes purchased, primarily related to natural gas, for optimization activities and long-term marketing arrangements associated with the Company’s previous divestitures ($163 million), partially offset by lower natural gas commodity prices ($61 million).
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Depreciation, Depletion & Amortization Proved properties within each country cost centre are depleted using theunit-of-production method based on proved reserves as discussed in Note 1 to the Consolidated Financial Statements included in Item 8 of the 2017 Annual Report on Form10-K. 10-K. Depletion rates are impacted by impairments, acquisitions, divestitures and foreign exchange rates, as well as fluctuations in12-month average trailing prices which affect proved reserves volumes. Additional information can be found in the Critical Accounting Estimates section of the MD&A included in Item 7 of the 2017 Annual Report on Form10-K. Corporate assets are carried at cost and depreciated on a straight-line basis over the estimated service lives of the assets. | | | | | | | | | | | | | Three months ended September 30, | | | | Nine months ended September 30, | | | | $ millions | | | | | | $/BOE | | | Three months ended March 31, | | 2018 | | | 2017 | | | | | | 2018 | | | 2017 | | | ($ millions) | | | | 2018 | | | 2017 | | | | 2018 | | | 2017 | | | | | | | | | | | | | | | | | | | | | | | | | | | Canadian Operations | | $ | 77 | | | $ | 64 | | | | | $ | 4.39 | | | $ | 4.11 | | | | $ | 95 | | | $ | 53 | | | | $ | 257 | | | $ | 170 | | | USA Operations | | | 185 | | | | 106 | | | | | $ | 15.84 | | | $ | 8.09 | | | | | 241 | | | | 139 | | | | | 628 | | | | 368 | | | Upstream DD&A | | | 262 | | | | 170 | | | | | $ | 8.98 | | | $ | 5.93 | | | | | 336 | | | | 192 | | | | | 885 | | | | 538 | | | | | | | | | | | | | | | | | | | | | | | | | Corporate and Other | | | 13 | | | | 17 | | | | | | | | | Market Optimization | | | | | - | | | | 1 | | | | | 1 | | | | 1 | | | Corporate & Other | | | | | 13 | | | | 17 | | | | | 38 | | | | 51 | | | Total | | $ | 275 | | | $ | 187 | | | | | | | | | | $ | 349 | | | $ | 210 | | | | $ | 924 | | | $ | 590 | | | | | | | | | | | | | | | | | | | | | | | | | | | | Three months ended September 30, | | | | Nine months ended September 30, | | ($/BOE) | | | | 2018 | | | 2017 | | | | 2018 | | | 2017 | | | | | | | | | | | | | | | | | | | | | | | | Canadian Operations | | | | $ | 4.57 | | | $ | 3.84 | | | | $ | 4.55 | | | $ | 3.89 | | | USA Operations | | | | $ | 17.05 | | | $ | 11.31 | | | | $ | 16.39 | | | $ | 9.22 | | | Upstream DD&A | | | | $ | 9.65 | | | $ | 7.35 | | | | $ | 9.34 | | | $ | 6.44 | | |
Three months ended March 31,September 30, 2018 versus March 31,September 30, 2017 DD&A increased $88$139 million compared to the firstthird quarter of 2017 primarily due to: Higher depletion rates in the USA and Canadian Operations ($79 million and $23 million, respectively) and higher volumes in the USA and Canadian Operations ($24 million and $22 million, respectively). | · | | Higher depletion rates primarily in the USA Operations ($91 million).
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The depletion raterates in the Canadian and USA Operations increased $3.05$0.73 per BOE and $5.74 per BOE, respectively, compared to the firstthird quarter of 2017 primarily due to: Higher capital spending resulting from an increased capital program in 2018 and transfers of unproved property costs of previously acquired assets which have been evaluated for proved reserves. | · | | Lower reserve volumes from the sale of the Piceance natural gas assets in the third quarter of 2017.
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Nine months ended September 30, 2018 versus September 30, 2017 DD&A increased $334 million compared to the first nine months of 2017 primarily due to: Higher depletion rates in the USA and Canadian Operations ($265 million and $42 million, respectively) and higher volumes in the Canadian Operations ($42 million). The depletion rates in the Canadian and USA Operations increased $0.66 per BOE and $7.17 per BOE, respectively, compared to the first nine months of 2017 primarily due to: Higher capital spending resulting from an increased capital program in 2018, transfers of unproved property costs of previously acquired assets which have been evaluated for proved reserves and lower reserve volumes from the sale of the Piceance natural gas assets in the USA Operations in the third quarter of 2017. Administrative Administrative expense represents costs associated with corporate functions provided by Encana staff in the Calgary and Denver offices. Costs primarily include salaries and benefits, general office, information technology and long-term incentive costs. | | | | | | | | | Three months ended March 31, | | | 2018 | | | 2017 | | | | Administrative ($ millions) | | $ | 31 | | | $ 58 | Administrative ($/BOE)(1) | | $ | 1.08 | | | $ 2.04 | (1) Administrative expense per BOE for the first quarter of 2018 includes a recovery of long-term incentive costs of $0.41/BOE (2017 - long-term incentive costs of $0.54/BOE). |
| Three months ended September 30, | | | | Nine months ended September 30, | | | 2018 | | | | 2017 | | | | 2018 | | | | 2017 | | | | | | | | | | | | | | | | | | | | | Administrative ($ millions) | $ | 57 | | | | $ | 86 | | | | $ | 187 | | | | $ | 168 | | Administrative ($/BOE) (1) | $ | 1.64 | | | | $ | 3.31 | | | | $ | 1.98 | | | | $ | 2.02 | |
(1) | Administrative expense per BOE for the third quarter and first nine months of 2018 includes long-term incentive costs of $0.47/BOE and $0.64/BOE, respectively (2017 - $1.68/BOE and $0.44/BOE, respectively). |
Three months ended March 31,September 30, 2018 versus March 31,September 30, 2017 Administrative expense in the third quarter of 2018 decreased $29 million compared to the third quarter of 2017 primarily due to lower long-term incentive costs in 2018 resulting from the smaller change in Encana’s share price in the third quarter of 2018 compared to 2017 ($26 million). Nine months ended September 30, 2018 versus September 30, 2017 Administrative expense in the first quarternine months of 2018 decreased $27increased $19 million compared to the first quarternine months of 2017 primarily due to a recovery ofhigher long-term incentive costs resulting from the decreaseincrease in Encana’s share price in the first nine months of 2018 ($2725 million), partially offset by legal costs incurred in 2017 ($5 million).
Other (Income) Expenses | Three months ended September 30, | | | | Nine months ended September 30, | | | ($ millions) | 2018 | | | | 2017 | | | | 2018 | | | | 2017 | | | | | | | | | | | | | | | | | | | | | Interest | $ | 92 | | | | $ | 101 | | | | $ | 265 | | | | $ | 268 | | Foreign exchange (gain) loss, net | | (23 | ) | | | | (210 | ) | | | | 93 | | | | | (294 | ) | (Gain) loss on divestitures, net | | - | | | | | (406 | ) | | | | (4 | ) | | | | (405 | ) | Other (gains) losses, net | | 5 | | | | | (11 | ) | | | | 2 | | | | | (46 | ) | Total Other (Income) Expenses | $ | 74 | | | | $ | (526 | ) | | | $ | 356 | | | | $ | (477 | ) |
Interest Interest expense primarily includes interest on Encana’s long-term debt arising from U.S. dollar denominated unsecured notes. Encana also incurs interest on the Company’s long-term obligation for The Bow office building and capital leases. Further details on changes in interest can be found in Note 5 to the Consolidated Financial Statements included in Part I, Item 1 of this Quarterly Report on Form 10-Q. | | | | | | | | | | | Three months ended March 31, | ($ millions) | | 2018 | | 2017 | | | | | Interest | | $ | 92 | | | $ | 88 | | Foreign exchange (gain) loss, net | | | 91 | | | | (26 | ) | (Gain) loss on divestitures, net | | | (3 | ) | | | 1 | | Other (gains) losses, net | | | (3 | ) | | | (8 | ) | Total Other (Income) Expenses | | $ | 177 | | | $ | 55 | |
Foreign Exchange (Gain) Loss, Net Foreign exchange gains and losses result from the impact of fluctuations in the Canadian to U.S. dollar exchange rate. Further details on changes in foreign exchange gains or losses can be found in Note 6 to the Consolidated Financial Statements included in Part I, Item 1 of this Quarterly Report on Form10-Q. Additional information on foreign exchange rates and the effects of foreign exchange rate changes can be found in Item 3 of this Quarterly Report on Form10-Q. In the third quarter of 2018, Encana recorded a lower net foreign exchange gain compared to 2017 ($187 million). The change was primarily due to lower unrealized foreign exchange gains on the translation of U.S. dollar financing debt issued from Canada compared to 2017 ($113 million) and unrealized foreign exchange losses on the translation of intercompany notes compared to gains in 2017 ($64 million). In the first quarternine months of 2018, Encana recorded a net foreign exchange loss compared to a net gain in 2017 ($117387 million). The change was primarily due to unrealized foreign exchange losses on the translation of U.S. dollar financing debt issued from Canada compared to gains in 2017 ($155403 million) and higher unrealized foreign exchange losses on the translation of intercompany notesU.S. dollar risk management contracts issued from Canada compared to gains in 2017 ($1860 million), partially offset by realized foreign exchange gains on the settlement of intercompany notes compared to losses in 2017 ($5265 million). (Gain) Loss on Divestitures, Net Income TaxAmounts received from the Company’s divestiture transactions are deducted from the respective Canadian and U.S. full cost pools, except for divestitures that result in a significant alteration between capitalized costs and proved reserves in a country cost centre, in which case a gain or loss is recognized. Additional information on gains on divestitures can be found in Note 8 to the Consolidated Financial Statements included in Part I, Item 1 of this Quarterly Report on Form 10-Q.
Gain on divestitures in the third quarter and first nine months of 2017 primarily includes the before tax gain on the sale of the Piceance natural gas assets. Further information on divestitures can be found in the Liquidity and Capital Resources section of this MD&A. | | | | | | | | | | | Three months ended March 31, | | ($ millions) | | 2018 | | | 2017 | | | | Current Income Tax Expense (Recovery) | | $ | 3 | | | $ | (39 | ) | Deferred Income Tax Expense (Recovery) | | | 6 | | | | 42 | | Income Tax Expense (Recovery) | | $ | 9 | | | $ | 3 | | | | | Effective Tax Rate | | | 5.6% | | | | 0.7% | |
Income Tax ExpenseOther (Gains) Losses, Net
Three months ended March 31, 2018 versus March 31, 2017Other (gains) losses, net, primarily includes other non-recurring revenues or expenses and may also include items such as interest income on short-term investments, interest received from tax authorities, reclamation charges relating to decommissioned assets and adjustments related to other assets.
Current income taxOther gains in the first quarternine months of 2018 was an expense2017 primarily includes interest received of $3$33 million compared to a recovery of $39 million in 2017. The current income tax recovery in 2017 resultedresulting from the successful resolution of certain tax items previously assessed by the taxingtax authorities relating to prior taxation years.
Deferred
Income Tax | | | Three months ended September 30, | | | | | Nine months ended September 30, | | ($ millions) | | | 2018 | | | 2017 | | | | | 2018 | | | 2017 | | | | | | | | | | | | | | | | | | | | | | Current Income Tax Expense (Recovery) | | | $ | - | | | $ | 1 | | | | | $ | (61 | ) | | $ | (56 | ) | Deferred Income 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 | % |
Income Tax Expense (Recovery) Three months ended September 30, 2018 versus September 30, 2017 In the third quarter of 2018, Encana recorded a lower income tax expense compared to 2017 primarily due to a lower deferred tax expense as a result of: Lower net earnings before income tax in 2018 compared to 2017; A reduction in the U.S. federal corporate tax rate to 21 percent from 35 percent resulting from U.S. Tax Reform; and Changes in the estimated annual effective income tax rate in 2017 arising from gains recognized on foreign exchange and divestitures, including allocated goodwill. Nine months ended September 30, 2018 versus September 30, 2017 In the first quarternine months of 2018, was $36 millionEncana recorded a lower thandeferred income tax expense compared to 2017 primarily due to:to lower net earnings before income tax compared to 2017 and U.S. Tax Reform, as discussed above. The deferred tax expense in the first nine months of 2017 was primarily due to changes in the estimated annual effective income tax rate as discussed above. | · | | Lower net earnings before income tax in 2018 compared to 2017; and
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| · | | A reduction in the U.S. federal corporate tax rate to 21 percent from 35 percent resulting from U.S. Tax Reform as enacted on December 22, 2017. Additional information on U.S. Tax Reform can be found in Note 6 to the Consolidated Financial Statements included in Item 8 of the 2017 Annual Report on Form10-K.
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There has been no change in the first quarter of 2018 to the provisional tax adjustment recognized in December 2017 resulting from there-measurement re‑measurement of theCompany’sthe Company’s tax position due to a reduction of the U.S.U.S federal corporate tax rate under U.S. Tax Reform. Additional information on U.S. Tax Reform can be found in Note 7 to the Consolidated Financial Statements included in Item 8 of the 2017 Annual Report on Form 10-K. Effective Tax Rate Encana’s interim income tax expense is determined using the 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, 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. The Company’sThese items resulted in an effective tax rate was 5.6 percent for the firstthird quarter of 2018 which is lower than the Canadian statutory rate of 27 percent primarily due toand an effective tax rate for the impactfirst nine months of the foreign jurisdictional tax rates relative to2018 that is above the Canadian statutory tax rate applied to jurisdictional earnings as well as the items discussed above.rate. Tax interpretations, regulations and legislation, including U.S. Tax Reform and potential Treasury Department regulations and guidance, in the various jurisdictions in which the Company and its subsidiaries operate are subject to change and interpretation. As a result, there are tax matters under review for which the timing of resolution is uncertain. The Company believes that the provision for income taxes is adequate. | Liquidity and Capital
Liquidity and Capital Resources |
Sources of Liquidity The Company has the flexibility to access cash equivalents and a range of funding alternatives at competitive rates through committed revolving bank credit facilities as well as debt and equity capital markets. Encana closely monitors the accessibility of cost-effective credit and ensures that sufficient liquidity is in place to fund capital expenditures and dividend payments. In addition, the Company may use cash and cash equivalents, cash from operating activities, or proceeds from asset divestitures and share issuances to fund its operations or to manage its capital structure as discussed below. At March 31,September 30, 2018, $303$229 million in cash and cash equivalents was held by U.S. subsidiaries. The cash held by U.S. subsidiaries is accessible and may be subject to additional Canadian income taxes and U.S. withholding taxes if repatriated. The Company’s capital structure consists of total shareholders’ equity plus long-term debt, including the current portion. The Company’s objectives when managing its capital structure are to maintain financial flexibility to preserve Encana’s access to capital markets and its ability to meet financial obligations and finance internally generated growth, as well as potential acquisitions. Encana has a practice of maintaining capital discipline and strategically managing its capital structure by adjusting capital spending, adjusting dividends paid to shareholders, issuing new shares, purchasing shares for cancellation through a NCIB, issuing new debt or repaying existing debt. | | | | | | | | | As at March 31, | ($ millions, except as indicated) | | 2018 | | | 2017 | | | | Cash and Cash Equivalents | | $ | 433 | | | $ 523 | Available Credit Facility – Encana(1) | | | 2,500 | | | 3,000 | Available Credit Facility – U.S. Subsidiary(1) | | | 1,500 | | | 1,500 | Total Liquidity | | | 4,433 | | | 5,023 | | | | Long-Term Debt | | | 4,198 | | | 4,198 | Total Shareholders’ Equity | | | 6,776 | | | 6,525 | | | | Debt to Capitalization (%)(2) | | | 38 | | | 39 | Debt to Adjusted Capitalization (%)(3) | | | 22 | | | 23 | (1) Collectively, the “Credit Facilities”. (2) Calculated as long-term debt, including the current portion, divided by shareholders’ equity plus long-term debt, including the current portion. (3) Anon-GAAP measure which is defined in theNon-GAAP Measures section of this MD&A. |
| | | As at September 30, | | ($ millions, except as indicated) | | | 2018 | | | 2017 | | | | | | | | | | | | Cash and Cash Equivalents | | | $ | 615 | | | $ | 889 | | Available Credit Facility – Encana (1) | | | | 2,500 | | | | 3,000 | | Available Credit Facility – U.S. Subsidiary (1) | | | | 1,500 | | | | 1,500 | | Total Liquidity | | | $ | 4,615 | | | $ | 5,389 | | | | | | | | | | | | Long-Term Debt, including current portion | | | $ | 4,198 | | | $ | 4,197 | | Total Shareholders’ Equity | | | $ | 6,494 | | | $ | 6,965 | | | | | | | | | | | | Debt to Capitalization (%) (2) | | | 39 | | | | 38 | | Debt to Adjusted Capitalization (%) (3) | | | 23 | | | | 22 | |
(1) | Collectively, the “Credit Facilities”. |
(2) | Calculated as long-term debt, including the current portion, divided by shareholders’ equity plus long-term debt, including the current portion. |
(3) | A non-GAAP measure which is defined in the Non-GAAP Measures section of this MD&A. |
In the first quarter of 2018, the Company amended the capacity of its Encana Credit Facility from $3.0 billion to $2.5 billion and extended the maturity for both Credit Facilities to July 2022. Encana is currently in compliance with, and expects that it will continue to be in compliance with, all financial covenants under the Credit Facilities. Management monitors Debt to Adjusted Capitalization, which is anon-GAAP measure defined in theNon-GAAP Measures section of this MD&A, as a proxy for Encana’s financial covenant under the Credit Facilities, which requires debt to adjusted capitalization to be less than 60 percent. The definitions used in the covenant under the Credit Facilities adjust capitalization for cumulative historical ceiling test impairments that were recorded as at December 31, 2011 in conjunction with the Company’s January 1, 2012 adoption of U.S. GAAP. Additional information on financial covenants can be found in Note 12 to the Consolidated Financial Statements included in Item 8 of the 2017 Annual Report on Form10-K.
Sources and Uses of Cash In the third quarter and first quarternine months of 2018, Encana primarily generated cash through operating activities. The following table summarizes the sources and uses of the Company’s cash and cash equivalents. | | | | | | Three months ended March 31, | | | | | Three months ended September 30, | | | | | Nine months ended September 30, | | ($ millions) | | Activity Type | | | 2018 | | 2017 | | Activity Type | | | 2018 | | | 2017 | | | | | 2018 | | | 2017 | | | | | | | | | | | | | | | | | | | | | | | | | Sources of Cash and Cash Equivalents | | | | | | | | | | | | | | | | | | | | | | | | | | | | Cash from operating activities | | | Operating | | | $ | 381 | | | $ | 106 | | | Operating | | | $ | 885 | | | $ | 357 | | | | | $ | 1,741 | | | $ | 681 | | Proceeds from divestitures | | | Investing | | | | 19 | | | 3 | | | Investing | | | | 24 | | | | 625 | | | | | | 89 | | | | 710 | | Other | | | Investing | | | | - | | | 55 | | | Investing | | | | - | | | | 14 | | | | | | 72 | | | | 93 | | | | | | | 400 | | | 164 | | | | | | | 909 | | | | 996 | | | | | | 1,902 | | | | 1,484 | | | | | | | | | | | | | | | | | | | | | | | | | | | Uses of Cash and Cash Equivalents | | | | | | | | | | | | | | | | | | | | | | | | | | | | Capital expenditures | | | Investing | | | | 508 | | | 399 | | | Investing | | | | 523 | | | | 473 | | | | | | 1,626 | | | | 1,287 | | Acquisitions | | | Investing | | | | 2 | | | 46 | | | Investing | | | | 15 | | | | 2 | | | | | | 17 | | | | 50 | | Purchase of common shares | | | Financing | | | | 111 | | | | - | | | Financing | | | | 50 | | | | - | | | | | | 250 | | | | - | | Dividends on common shares | | | Financing | | | | 15 | | | 15 | | | Financing | | | | 14 | | | | 14 | | | | | | 43 | | | | 43 | | Other | | | Investing/Financing | | | | 47 | | | 16 | | | Investing/Financing | | | | 31 | | | | 21 | | | | | | 68 | | | | 61 | | | | | | | 683 | | | 476 | | | | | | | 633 | | | | 510 | | | | | | 2,004 | | | | 1,441 | | Foreign Exchange Gain (Loss) on Cash and Cash Equivalents Held in Foreign Currency | | | | | (3 | ) | | 1 | | | | | | | 3 | | | | 8 | | | | | | (2 | ) | | | 12 | | | | | | | | | | | | | | | | | | | | | | | | | Increase (Decrease) in Cash and Cash Equivalents | | | | $ | (286 | ) | | $ | (311 | ) | Increase (Decrease) in Cash and Cash Equivalents | | | $ | 279 | | | $ | 494 | | | | | $ | (104 | ) | | $ | 55 | |
Operating Activities Cash from operating activities in the third quarter and first quarternine months of 2018 was $381$885 million and $1,741 million, respectively, and was primarily a reflection of recovering commodityliquids prices, increases in production volumes, the Company’s efforts in maintaining cost efficiencies achieved in previous years changes in production volumes and changes innon-cash working capital. Additional detail on changes innon-cash working capital can be found in Note 20 to the Consolidated Financial Statements included in Part I, Item 1 of this Quarterly Report on Form10-Q. Encana expects it will continue to meet the payment terms of its suppliers. Non-GAAP Cash Flow in the third quarter and first quarternine months of 2018 was $400$589 million and $1,575 million, respectively. Non-GAAP Cash Flow was primarily impacted by the items affecting cash from operating activities which are discussed below and in the Results of Operations section of this MD&A. Three months ended March 31,September 30, 2018 versus March 31,September 30, 2017 Net cash from operating activities in the first quarter of 2018 increased $275$528 million compared to the firstthird quarter of 2017 primarily due to: Higher realized commodity prices ($286 million), higher production volumes ($228 million) and changes in non-cash working capital ($215 million); | · | | Changes in non-cash working capital ($152 million), higher realized commodity prices ($129 million) and higher production volumes ($79 million).
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partially offset by: Realized losses on risk management in revenues in the third quarter of 2018 compared to realized gains in 2017 ($118 million) and higher transportation and processing expense ($79 million). Nine months ended September 30, 2018 versus September 30, 2017 Net cash from operating activities increased $1,060 million compared to the first nine months of 2017 primarily due to: Higher realized commodity prices ($581million), higher production volumes ($394 million) and changes in non-cash working capital ($390million); partially offset by: Higher transportation and processing expense ($182million), realized losses on risk management in revenues in the first nine months of 2018 compared to realized gains in 2017 ($131 million) and lower interest income recorded in other gains ($27 million). | · | | A current tax expense in the first quarter of 2018 compared to a recovery in 2017 ($42 million), and higher transportation and processing expense ($37 million).
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Investing Activities Cash used in investing activities in the first quarternine months of 2018 was $516$1,482 million primarily due to capital expenditures. Capital expenditures totaled $508 million, whichin the first nine months of 2018 increased $109$339 million compared to the first quarter of 2017 due to an increase in Encana’sthe Company’s capital program for 2018. This increase was primarily in Montney ($94221 million) and PermianEagle Ford ($4170 million). Capital expenditures exceeded cash from operating activities by $127 million and the difference was funded using cash on hand. Divestitures in the first quarternine months of 2018 andwere $89 million, which primarily included the sale of the Pipestone midstream assets in Alberta. Divestitures in the first nine months of 2017 were $19$710 million, and $3 million, respectively, which primarily included the sale of the Piceance natural gas assets in northwestern Colorado and the sale of the Tuscaloosa Marine Shale assets in Mississippi and Louisiana. Divestitures also included the sale of certain properties that did not complement Encana’sEncana's existing portfolio of assets. Acquisitions in the first quarternine months of 2018 and 2017 were $2$17 million and $46$50 million, respectively, which primarily included land purchases with oil and liquids rich potential. Capital expenditures and acquisition and divestiture activity are summarized in Notes 3 and 8 to the Consolidated Financial Statements included in Part I, Item 1 of this Quarterly Report on Form10-Q. On April 2, 2018, Encana announced an agreement with Keyera Partnership, a subsidiary of Keyera Corp., to sell the Company’s Pipestone liquids hub in Alberta. In conjunction with the sale, Keyera will own and construct a natural gas processing facility and provide Encana with processing services under a competitivefee-for-service arrangement in support of the Company’s liquids growth plans in Montney. The effective date of the agreement is March 1, 2018.
Financing Activities Net cash used in financing activities in the first quarternine months of 2018 increased $117$257 million compared to the first quarternine months of 2017. The change was primarily due to the purchase of common shares under a NCIB in the first quarternine months of 2018 ($111250 million) as discussed below. Encana’s long-term debt, including the current portion of $500 million which is due May 2019, totaled $4,198 million at March 31,September 30, 2018 and $4,197 million at December 31, 2017. There was no current portion of long-term debt outstanding at March 31, 2018 or December 31, 2017. Encana has no long-term debt maturities until May 2019 and, asAs at March 31,September 30, 2018, over 73 percent of the Company’s debt is not due until 2030 and beyond. The Company continues to have full access to the Credit Facilities, which remain committed through July 2022. The Credit Facilities provide financial flexibility and allow the Company to fund its operations, development activities or capital program. At March 31,September 30, 2018, Encana had no outstanding balance under the Credit Facilities.Facilities and $144 million in undrawn letters of credit issued in the normal course of business primarily as collateral security, to support future abandonment liabilities and for transportation arrangements. Encana renewed its Canadian shelf prospectus in August 2018 and has access to a U.S. shelf registration statement filed in 2017, whereby the Company may issue from time to time, debt securities, common shares, Class A preferred shares, subscription receipts, warrants, units, share purchase contracts and share purchase units in Canada and/or the U.S. At September 30, 2018, $6.0 billion remained accessible under the Canadian shelf prospectus. The ability to issue securities under the Canadian shelf prospectus or U.S. shelf registration statement is dependent upon market conditions. Dividends Encana pays quarterly dividends to shareholders at the discretion of the Board of Directors. | | | Three months ended March 31, | | Three months ended September 30, | | | | Nine months ended September 30, | | | ($ millions, except as indicated) | | 2018 | | 2017 | | 2018 | | | | 2017 | | | | 2018 | | | | 2017 | | | | | | | | | | | | | | | | | | | | | | | Dividend Payments | | $ | 15 | | | $ | 15 | | $ | 14 | | | | $ | 15 | | | | $ | 43 | | | | $ | 44 | | Dividend Payments ($/share) | | $ | 0.015 | | | $ | 0.015 | | $ | 0.015 | | | | $ | 0.015 | | | | $ | 0.045 | | | | $ | 0.045 | |
On April 30,October 31, 2018, the Board of Directors declared a dividend of $0.015 per common share payable on June 29,December 31, 2018 to common shareholders of record as of June 15,December 14, 2018. Normal Course Issuer Bid On February 26, 2018, Encana received approval from the TSX to commence a NCIB that enables the Company to purchase, for cancellation, up to 35 million common shares over a12-month period from February 28, 2018 to February 27, 2019. The number of shares authorized for purchase represents approximately 3.6 percent of Encana’s issued and outstanding common
shares as at February 20, 2018. The Company has authorization from its Board to spend up to $400 million on the NCIB. InFor the third quarter and first quarternine months of 2018, the Company purchased 10used cash on hand to purchase approximately 3.9 million and 20.7 million common shares, respectively, for total consideration of approximately $111 million. The Company plans to fund the NCIB with cash on hand.$50 million and $250 million, respectively. For additional information on NCIB, refer to Note 13 to the Consolidated Financial Statements included in Part I, Item 1 of this Quarterly Report on Form10-Q. Off-Balance Sheet Arrangements For information onoff-balance sheet arrangements and transactions, refer to theOff-Balance Sheet Arrangements section of the MD&A included in Item 7 of the 2017 Annual Report on Form10-K. Commitments and Contingencies For information on commitments and contingencies, refer to Note 21 to the Consolidated Financial Statements included in Part I, Item 1 of this Quarterly Report on Form10-Q. Non-GAAP Measures Certain measures in this document do not have any standardized meaning as prescribed by U.S. GAAP and, therefore, are considerednon-GAAP measures. These measures may not be comparable to similar measures presented by other issuers and should not be viewed as a substitute for measures reported under U.S. GAAP. These measures are commonly used in the oil and gas industry and by Encana to provide shareholders and potential investors with additional information regarding the Company’s liquidity and its ability to generate funds to finance its operations.Non-GAAP measures include:Non-GAAP Cash Flow,Non-GAAP Cash Flow Margin, Debt to Adjusted Capitalization and Net Debt to Adjusted EBITDA. Management’s use of these measures is discussed further below. Non-GAAP Cash Flow andNon-GAAP Cash Flow Margin Non-GAAP Cash Flow is anon-GAAP measure defined as cash from (used in) operating activities excluding net change in other assets and liabilities, net change innon-cash working capital and current tax on sale of assets. Non-GAAP Cash Flow Margin is anon-GAAP measure defined asNon-GAAP Cash Flow per BOE of production. Management believes these measures are useful to the Company and its investors as a measure of operating and financial performance across periods and against other companies in the industry, and are an indication of the Company’s ability to generate cash to finance capital programs, to service debt and to meet other financial obligations. These measures are used, along with other measures, in the calculation of certain performance targets for the Company’s management and employees. | | | Three months ended March 31, | | | | Three months ended September 30, | | | | Nine months ended September 30, | | ($ millions, except as indicated) | | 2018 | | 2017 | | | | 2018 | | | 2017 | | | | 2018 | | | 2017 | | | | | | | | | | | | | | | | | | | | | | | Cash From (Used in) Operating Activities | | $ | 381 | | | $ | 106 | | | | $ | 885 | | | $ | 357 | | | | $ | 1,741 | | | $ | 681 | | (Add back) deduct: | | | | | | | | | | | | | | | | | | | | | | | Net change in other assets and liabilities | | | (11 | ) | | (12) | | | | | (17 | ) | | | (11 | ) | | | | (33 | ) | | | (27 | ) | Net change innon-cash working capital | | | (8 | ) | | (160) | | | | | 313 | | | | 98 | | | | | 199 | | | | (191 | ) | Current tax on sale of assets | | | - | | | | - | | | | | - | | | - | | | | | | - | | | - | | Non-GAAP Cash Flow | | $ | 400 | | | $ | 278 | | | | $ | 589 | | | $ | 270 | | | | $ | 1,575 | | | $ | 899 | | Production Volumes (MMBOE) | | | 29.2 | | | 28.6 | | | | | 34.8 | | | | 26.1 | | | | | 94.7 | | | | 83.5 | | Non-GAAP Cash Flow Margin ($/BOE) (1) | | $ | 13.70 | | | $ | 9.72 | | | | $ | 16.93 | | | $ | 10.34 | | | | $ | 16.63 | | | $ | 10.77 | |
| (1) | Non-GAAP Cash Flow Margin was previously presented as Corporate Margin. |
Debt to Adjusted Capitalization
Debt to Adjusted Capitalization is anon-GAAP measure which adjusts capitalization for historical ceiling test impairments that were recorded as at December 31, 2011. Management monitors Debt to Adjusted Capitalization as a proxy for Encana’s financial covenant under the Credit Facilities which require debt to adjusted capitalization to be less than 60 percent. Adjusted Capitalization includes debt, total shareholders’ equity and an equity adjustment for cumulative historical ceiling test impairments recorded as at December 31, 2011 in conjunction with the Company’s January 1, 2012 adoption of U.S. GAAP. | ($ millions, except as indicated) | | March 31, 2018 | | | December 31, 2017 | | | | September 30, 2018 | | | December 31, 2017 | | | | | | | | | | | | | | Debt | | | $ 4,198 | | | | $ 4,197 | | | Long-Term Debt, including current portion | | | | $ | 4,198 | | | $ | 4,197 | | Total Shareholders’ Equity | | | 6,776 | | | | 6,728 | | | | | 6,494 | | | | 6,728 | | Equity Adjustment for Impairments at December 31, 2011 | | | 7,746 | | | | 7,746 | | | | | 7,746 | | | | 7,746 | | Adjusted Capitalization | | | $ 18,720 | | | | $ 18,671 | | | | $ | 18,438 | | | $ | 18,671 | | Debt to Adjusted Capitalization | | | 22% | | | | 22% | | | | 23% | | | 22% | |
Net Debt to Adjusted EBITDA Net Debt to Adjusted EBITDA is anon-GAAP measure whereby Net Debt is defined as long-term debt, including the current portion, less cash and cash equivalents and Adjusted EBITDA is defined as trailing12-month net earnings (loss) before income taxes, DD&A, impairments, accretion of asset retirement obligation, interest, unrealized gains/losses on risk management, foreign exchange gains/losses, gains/losses on divestitures and other gains/losses. Management believes this measure is useful to the Company and its investors as a measure of financial leverage, the Company’s ability to service its debt and other financial obligations, and as a measure considered comparable to other companies in the industry. This measure is used, along with other measures, in the calculation of certain financial performance targets for the Company’s management and employees. | ($ millions, except as indicated) | | March 31, 2018 | | December 31, 2017 | | | | September 30, 2018 | | | December 31, 2017 | | | | | | | | | | | | | | Long-Term Debt, including current portion | | | $ 4,198 | | | $ 4,197 | | | | $ | 4,198 | | | $ | 4,197 | | Less: | | | | | | | | | | | | | | Cash and cash equivalents | | | 433 | | | 719 | | | | | 615 | | | | 719 | | Net Debt | | | 3,765 | | | 3,478 | | | | | 3,583 | | | | 3,478 | | | | | | | | | | | | | | Net Earnings (Loss) | | | 547 | | | 827 | | | | | (190 | ) | | | 827 | | Add back (deduct): | | | | | | | | | | | | | | Depreciation, depletion and amortization | | | 921 | | | 833 | | | | | 1,167 | | | | 833 | | Impairments | | | - | | | | - | | | | | - | | | | - | | Accretion of asset retirement obligation | | | 34 | | | 37 | | | | | 31 | | | | 37 | | Interest | | | 367 | | | 363 | | | | | 360 | | | | 363 | | Unrealized (gains) losses on risk management | | | (148 | ) | | (442) | | | | | 376 | | | | (442 | ) | Foreign exchange (gain) loss, net | | | (162 | ) | | (279) | | | | | 108 | | | | (279 | ) | (Gain) loss on divestitures, net | | | (408 | ) | | (404) | | | | | (3 | ) | | | (404 | ) | Other (gains) losses, net | | | (37 | ) | | (42) | | | | | 6 | | | | (42 | ) | Income tax expense (recovery) | | | 609 | | | 603 | | | | | 321 | | | | 603 | | Adjusted EBITDA | | | $ 1,723 | | | $ 1,496 | | | Adjusted EBITDA (trailing 12-month) | | | | $ | 2,176 | | | $ | 1,496 | | Net Debt to Adjusted EBITDA (times) | | | 2.2 | | | 2.3 | | | | | 1.6 | | | | 2.3 | |
Item 3: Quantitative and QualitativeQualitative Disclosures About Market Risk The primary objective of the following information is to provide forward-looking quantitative and qualitative information about Encana’s potential exposure to market risks. The term “market risk” refers to the Company’s risk of loss arising from adverse changes in oil, NGL and natural gas prices, foreign currency exchange rates and interest rates. The following disclosures are not meant to be precise indicators of expected future losses but rather indicators of reasonably possible losses. The forward-looking information provides indicators of how the Company views and manages ongoing market risk exposures. The Company’s policy is to not use derivative financial instruments for speculative purposes. COMMODITY PRICE RISK Commodity price risk arises from the effect fluctuations in future commodity prices, including oil, NGLs and natural gas, may have on future revenues, expenses and cash flows. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to the Company’s natural gas production. Pricing for oil and natural gas production has been volatile and unpredictable as discussed in Item 1A. “Risk Factors” of the 2017 Annual Report on Form10-K. To partially mitigate exposure to commodity price risk, the Company may enter into various derivative financial instruments including futures, forwards, swaps, options and costless collars. The use of these derivative instruments is governed under formal policies and is subject to limits established by the Board of Directors and may vary from time to time. Both exchange traded andover-the-counter traded derivative instruments may be subject to margin-deposit requirements, and the Company may be required from time to time to deposit cash or provide letters of credit with exchange brokers or counterparties to satisfy these margin requirements. For additional information relating to the Company’s derivative and financial instruments, see Note 19 under Part I, Item 1 of this Quarterly Report on Form10-Q. The table below summarizes the sensitivity of the fair value of the Company’s risk management positions to fluctuations in commodity prices, with all other variables held constant. The Company has used a 10 percent variability to assess the potential impact of commodity price changes. Fluctuations in commodity prices could have resulted in unrealized gains (losses) impactingpre-tax net earnings as follows: | | | March 31, 2018 | | | September 30, 2018 | | (US$ millions) | | | 10% Price Increase | | | 10% Price Decrease | | | 10% Price Increase | | | 10% Price Decrease | | Crude oil price | | | | $ | (303) | | | $ | 293 | | | $ | (307 | ) | | $ | 286 | | NGL price | | | | (20 | ) | | | 20 | | Natural gas price | | | | | 24 | | | | (31) | | | | (47 | ) | | | 41 | |
FOREIGN EXCHANGE RISK Foreign exchange risk arises from changes in foreign exchange rates that may affect the fair value or future cash flows of the Company’s financial assets or liabilities. As Encana operates in Canada and the United States, fluctuations in the exchange rate between the U.S. and Canadian dollars can have a significant effect on the Company’s reported results. Although Encana’s financial results are consolidated in Canadian dollars, the Company reports its results in U.S. dollars as most of its revenues are closely tied to the U.S. dollar and to facilitate a more direct comparison to other North American oil and gas companies. The table below summarizes selected foreign exchange impacts on Encana’s financial results in the first quarter of 2018when compared to the same periodperiods in 2017. | | | $ millions | | | $/BOE | | | Three Months Ended September 30, | | | Nine Months Ended September 30, | | | | | $ millions | | | $/BOE | | | $ millions | | | $/BOE | | Increase (Decrease) in: | | | | | | | | | | | | | | | | | | | | | | Capital Investment | | $ | 4 | | | | | $ | (6 | ) | | | | | | $ | 2 | | | | | | | Transportation and Processing Expense(1) | | | 6 | | | $ | 0.21 | | | | (6 | ) | | $ | (0.17 | ) | | | 6 | | | $ | 0.06 | | | Operating Expense(1) | | | 1 | | | | 0.05 | | | | (1 | ) | | | (0.04 | ) | | | 1 | | | | 0.01 | | | Administrative Expense | | | 2 | | | | 0.06 | | | | (3 | ) | | | (0.07 | ) | | | - | | | | - | | | Depreciation, Depletion and Amortization(1) | | | 3 | | | | 0.10 | | | | (2 | ) | | | (0.06 | ) | | | 3 | | | | 0.03 | |
(1) | Reflects upstream operations. |
Foreign exchange gains and losses also arise when monetary assets and monetary liabilities denominated in foreign currencies are translated and settled, and primarily include: U.S. dollar denominated financing debt issued from Canada | · | | U.S. dollar denominated financing debt issued from Canada
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| · | | U.S. dollar denominated risk management assets and liabilities held in Canada
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| · | | U.S. dollar denominated cash and short-term investments held in Canada
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| · | | Foreign denominated intercompany loans
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U.S. dollar denominated risk management assets and liabilities held in Canada U.S. dollar denominated cash and short-term investments held in Canada Foreign denominated intercompany loans 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 March 31,September 30, 2018, Encana has entered into $538$179 million notional U.S. dollar denominated currency swaps at an average exchange rate of US$0.7606 to C$1, which mature monthly through the remainder of 2018.2018 and $350 million notional U.S. dollar denominated currency swaps at an average exchange rate of US$0.7579 to C$1, which mature monthly throughout 2019. As at March 31,September 30, 2018, Encana had $4.2 billion in U.S. dollar long-term debt and $296$259 million in U.S. dollar capital leases issued from Canada that were subject to foreign exchange exposure. The table below summarizes the sensitivity to foreign exchange rate fluctuations, with all other variables held constant. The Company has used a 10 percent variability to assess the potential impact from Canadian to U.S. foreign currency exchange rate changes. Fluctuations in foreign currency exchange rates could have resulted in unrealized gains (losses) impactingpre-tax net earnings as follows: | | | March 31, 2018 | | | September 30, 2018 | | (US$ millions) | | 10% Rate Increase | | 10% Rate Decrease | | | 10% Rate Increase | | | 10% Rate Decrease | | | Foreign currency exchange | | $ | (394 | ) | | $ | 482 | | | $ | (106 | ) | | $ | 129 | |
INTEREST RATE RISK Interest rate risk arises from changes in market interest rates that may affect the fair value or future cash flows from the Company’s financial assets or liabilities. The Company may partially mitigate its exposure to interest rate changes by holding a mix of both fixed and floating rate debt and may also enter into interest rate derivatives to partially mitigate effects of fluctuations in market interest rates. As at March 31,September 30, 2018, the Company had no floating rate debt and there were no interest rate derivatives outstanding.
Item 4: Controls and Procedures
DISCLOSURE CONTROLS AND PROCEDURES Encana’s Chief Executive Officer and Chief Financial Officer performed an evaluation of the Company’s disclosure controls and procedures as defined in Rules13a-15(e) and15d-15(e) of the Securities Exchange Act of 1934, as amended (“Exchange Act”). The Company’s disclosure controls and procedures are designed to ensure that information required to be disclosed by the Company in reports it files or submits under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the rules and forms of the SEC, and to ensure that the information required to be disclosed by the Company in reports that it files or submits under the Exchange Act, is accumulated and communicated to the Company’s management, including the principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure. Based on this evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that the Company’s disclosure controls and procedures were effective as of March 31,September 30, 2018.
CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING There were no changes in Encana’s internal control over financial reporting during the firstsecond quarter of 2018 that materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
PART II Item 1. Legal Proceedings Please refer to Item 3 of the 2017 Annual Report on Form10-K and Note 21 of Encana’s Condensed Consolidated Financial Statements under Part I, Item 1 of this Quarterly Report on Form10-Q.
Item 1A. Risk Factors There have been no material changes from
In addition to the riskother information set forth in this Quarterly Report on Form 10-Q, the reader should carefully consider the factors discloseddiscussed in Item 1A. Risk Factors of the 2017 Annual Report on Form 10-K. These risks, which could materially affect our business, financial condition or future results, are not the only risks we face. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial may also adversely affect our business, financial condition and/or operating results. In addition to the risk factors previously disclosed in the 2017 Annual Report on Form10-K. 10-K, the following are risks related to our pending acquisition of Newfield:
The transactions contemplated by the merger agreement are subject to conditions, including certain conditions that may not be satisfied, or completed on a timely basis, if at all. Failure to complete the transactions contemplated by the merger agreement, including the merger, could have material and adverse effects on Encana. Completion of the merger is subject to a number of conditions, including, among other things, (i) the receipt of certain approvals of Encana shareholders and Newfield stockholders, (ii) the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, (iii) the effectiveness of the registration statement on Form S-4 that Encana is obligated to file with the SEC in connection with the issuance of Encana common shares in the merger, (iv) the authorization for listing of the Encana common shares to be issued in the merger on the NYSE and the TSX, (v) the accuracy of each party’s representations and warranties (subject to certain materiality qualifiers) and compliance by each party with its covenants under the merger agreement in all material respects and (vi) the absence of legal restraints prohibiting or restraining the merger. Such conditions make the completion and timing of the completion of the transaction uncertain. In addition, the merger agreement contains certain termination rights for both Newfield and Encana. If the merger agreement is terminated under certain circumstances, Encana could be required to pay Newfield a termination fee of $300 million. In other circumstances, upon termination of the merger agreement, Encana could be required to pay Newfield $50 million for costs, fees and expenses incurred by Newfield. See our Current Report on Form 8-K filed with the SEC on November 2, 2018 for a more detailed discussion of the conditions to the completion of the merger and termination rights under the merger agreement. If the transactions contemplated by the merger agreement are not completed, Encana’s ongoing business may be adversely affected and, without realizing any of the benefits of having completed the transaction, Encana will be subject to a number of risks, including the following: Encana will be required to pay its costs relating to the transaction, such as legal, accounting, financial advisory and printing fees, whether or not the transaction is completed; time and resources committed by Encana’s management to matters relating to the transaction could otherwise have been devoted to pursuing other beneficial opportunities; the market price of Encana common shares could be impacted to the extent that the current market price reflects a market assumption that the transaction will be completed; and if the merger agreement is terminated and the Encana Board of Directors seeks another acquisition, Encana shareholders cannot be certain that Encana will be able to find a party willing to enter into a transaction as attractive to Encana as the acquisition of Newfield. Encana will be subject to business uncertainties while the merger is pending, which could adversely affect its business. In connection with the pendency of the transaction, it is possible that certain persons with whom Encana has a business relationship may delay or defer certain business decisions or might decide to seek to terminate, change or renegotiate their relationships with Encana, as a result of the transaction, which could negatively affect Encana’s revenues, earnings and cash flows, as well as the market price of Encana’s common shares, regardless of whether the merger is completed. Under the terms of the merger agreement, Encana is subject to certain restrictions on the conduct of its business prior to the completion of the transaction, which may adversely affect its ability to execute certain of its business strategies, including the
ability in certain cases to enter into certain contracts, acquire or dispose of certain assets or incur certain indebtedness or capital expenditures. Such limitations could negatively affect Encana’s business and operations prior to the completion of the transaction. Encana shareholders will have a reduced ownership in the combined company. In connection with the completion of the merger and the transactions contemplated by the merger agreement, based on the number of issued and outstanding shares of Newfield common stock as of October 29, 2018 and the number of outstanding Newfield equity awards currently estimated to be payable in our common shares in connection with the merger, Encana anticipates issuing up to approximately 547.5 million common shares. The actual number of Encana common shares to be issued in the merger will be determined at the completion of the merger based on the number of shares of Newfield common stock outstanding at the time of the consummation of the merger. The issuance of these new shares could have the effect of depressing the market price of Encana’s common shares, through dilution of earnings per share or otherwise. Any dilution of, or delay of any accretion to, Encana’s earnings per share could cause the price of its common shares to decline or increase at a reduced rate. The transaction will also dilute the current ownership position and voting interest of Encana’s shareholders. Immediately after the merger is completed, it is expected that current Encana shareholders will own approximately 63.5% and Newfield stockholders will own approximately 36.5% of the combined company’s common shares outstanding, respectively. As a result, current Encana shareholders will have less influence on the policies of the combined company than they currently have. The market price of Encana common shares could be negatively affected by risks and conditions that apply to Newfield, which may be different from the risks and conditions currently applicable to Encana. Following the merger, Encana shareholders will own interests in a combined company operating an expanded business with more assets and a different mix of liabilities, in various jurisdictions in which Encana does not currently operate in. There is a risk that various factors, conditions and developments that would not currently affect the price of Encana common shares could, following the merger, negatively affect the price of Encana common shares. In addition, current Encana shareholders may not continue to invest in the combined company or may wish to reduce their investment in the combined company. If, following the merger, significant amounts of Encana common shares are sold, the price of Encana common shares could decline. If the merger is completed, Encana may not achieve the intended benefits and the transaction may disrupt its current plans or operations. There can be no assurance that Encana will be able to successfully integrate Newfield’s assets or otherwise realize the expected benefits of the transaction. Difficulties in integrating Newfield into Encana may result in the combined company performing differently than expected, in operational challenges or in the failure to realize anticipated expense-related efficiencies. Potential difficulties that may be encountered in the integration process include, among other factors: the inability to successfully integrate the businesses of Newfield into Encana in a manner that permits Encana to achieve the full revenue and cost savings anticipated from the transaction; complexities associated with managing a larger, more complex, integrated business; not realizing anticipated operating synergies; integrating personnel from the two companies and the loss of key employees; potential unknown liabilities and unforeseen expenses, delays or regulatory conditions associated with and following completion of the transaction; integrating relationships with vendors and business partners; performance shortfalls at one or both of the companies as a result of the diversion of management’s attention caused by completing the transaction and planning to integrate Newfield’s operations into Encana; and the disruption of, or the loss of momentum in, each company’s ongoing business or inconsistencies between the company’s standards, controls, procedures and policies. Completion of the merger may trigger change in control or other provisions in certain agreements to which Newfield is a party. The completion of the transaction may trigger change in control or other provisions in certain agreements to which Newfield is a party. If Encana and Newfield are unable to negotiate waivers of those provisions, the counterparties may exercise their rights and remedies under the agreements, potentially terminating the agreements or seeking monetary damages or Encana
may be required to make an offer to purchase outstanding debt securities of Newfield. Even if Encana and Newfield are able to negotiate waivers, the counterparties may require a fee for such waivers or seek to renegotiate the agreements. Encana is expected to incur significant transaction and acquisition-related costs in connection with the merger. Encana has incurred and is expected to continue to incur a number of non-recurring costs associated with negotiating and completing the transaction, combining the operations of the two companies and achieving desired synergies. These costs may be substantial and, in many cases, will be borne by Encana whether or not the transaction is completed. A substantial majority of non-recurring expenses will consist of transaction costs and include, among others, fees paid to financial, legal and other advisors, employee retention, severance and benefit costs and filing fees. Encana will also incur costs related to formulating and implementing integration plans, including facilities and systems consolidation costs and other employment-related costs. Encana continues to assess the magnitude of these costs, and additional unanticipated costs may be incurred in connection with the integration of the two companies’ businesses. The elimination of duplicative costs, as well as the realization of other efficiencies related to the integration of the businesses, may not initially offset integration-related costs or achieve a net benefit in the near term, or at all. Any unanticipated costs and expenses could have an adverse effect on Encana’s financial condition and operating results following the completion of the transaction. Item 2. Unregistered Sales of Equity Securities and Use of Proceeds Issuer Purchase of Equity Securities On February 26, 2018, Encana announced it had received approval from the TSX to purchase, for cancellation, up to 35 million common shares pursuant to a normal course issuer bid (“NCIB”)NCIB over a12-month period from February 28, 2018 to February 27, 2019. During the three months ended March 31,September 30, 2018, the Company purchased 103.9 million common shares for total consideration of approximately $111$50 million at a weighted average price of $11.11.$12.86. The following table presents the common shares purchased during the three months ended March 31,September 30, 2018. | | | | | | | | | | | | | | | | | Period | | Total Number of Shares Purchased | | | Average Price Paid per Share (1) | | | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs | | | Maximum Number of Shares That May Yet be Purchased Under the Plans or Programs | | | | | | | January 1 to January 31, 2018 | | | - | | | $ | - | | | | - | | | | - | | February 1 to February 28, 2018 | | | - | | | | - | | | | - | | | | 35,000,000 | | March 1 to March 31, 2018 | | | 10,000,000 | | | | 11.11 | | | | 10,000,000 | | | | 25,000,000 | | | | | | | Total | | | 10,000,000 | | | $ | 11.11 | | | | 10,000,000 | | | | 25,000,000 | |
Period | | Total Number of Shares Purchased | | | Average Price Paid per Share (1) | | | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs | | | Maximum Number of Shares That May Yet be Purchased Under the Plans or Programs | | July 1 to July 31, 2018 | | | - | | | $ | - | | | | - | | | | 18,190,000 | | August 1 to August 31, 2018 | | | 1,875,000 | | | | 13.09 | | | | 1,875,000 | | | | 16,315,000 | | September 1 to September 30, 2018 | | | 2,000,000 | | | | 12.65 | | | | 2,000,000 | | | | 14,315,000 | | Total | | | 3,875,000 | | | $ | 12.86 | | | | 3,875,000 | | | | 14,315,000 | |
(1) Includes commissions. Item 3. Defaults Upon Senior Securities None.
Item 4. Mine Safety Disclosures Not applicable.
Item 5. Other Information None.
Item 6. ExhibitsExhibits | | | Exhibit No | | Description | 10.1
| | First Amending Agreement dated as of March 28, 2018, among Encana Corporation as borrower, the financial institutions party thereto as lenders and Royal Bank of Canada as agent (incorporated by reference to Exhibit 10.1 to Encana’s Current Report on Form8-K filed on March 29, 2018, SEC FileNo. 001-15226). | 10.2
| | Successor Agent Agreement and Amendment No. 4 to the Credit Agreement dated as of March 28, 2018, among Alenco Inc. as borrower, the banks, financial institutions and other institutional lenders thereto as lenders, JPMorgan Chase Bank, N.A., in its capacity as successor administrative agent, and Citibank, N.A., in its capacity as existing administrative agent (incorporated by reference to Exhibit 10.2 to Encana’s Current Report on Form8-K filed on March 29, 2018, SEC FileNo. 001-15226). | 31.1 | | Certification of Chief Executive Officer pursuant to Rule13a-14(a) or15d-14(a) of the Securities Exchange Act of 1934. | 31.2 | | Certification of Chief Financial Officer pursuant to Rule13a-14(a) or15d-14(a) of the Securities Exchange Act of 1934. | 32.1 | | Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350. | 32.2 | | Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350. | 101.INS | | XBRL Instance Document. | 101.SCH | | XBRL Taxonomy Schema Document. | 101.CAL | | XBRL Calculation Linkbase Document. | 101.DEF | | XBRL Definition Linkbase Document. | 101.LAB | | XBRL Label Linkbase Document. | 101.PRE | | XBRL Presentation Linkbase Document. |
SIGNATURESSIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. | | | | ENCANA CORPORATION | ENCANA CORPORATION | | | By: | | /s/ Sherri A. Brillon | | | | | Name: | Name: | | Sherri A. Brillon | | Title: | Title: | | Executive Vice-President & Chief Financial Officer |
Dated: May 3,November 6, 2018 5766
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