Demonstrating its focus on shareholder returns,
Full-year and fourth quarter 2017 highlights include:
- Net earnings of
$827 million, up from a net loss of $944 millionin 2016.
- Cash from operating activities of
$1.1 billion, up over 65 percent from 2016; fourth quarter cash from operating activities of $369 million, up 85 percent from the fourth quarter of 2016.
- Non-GAAP cash flow of
$1.3 billion, up 60 percent from 2016; fourth quarter non-GAAP cash flow of $444 million, up 47 percent from the fourth quarter of 2016.
- Non-GAAP cash flow margin up 81 percent from 2016 to
$11.75per barrel of oil equivalent (BOE), significantly exceeding the original 2017 target of $10per BOE.
- Core asset production growth of 31 percent from the fourth quarter of 2016 to the fourth quarter of 2017, significantly exceeding the original 2017 target of greater than 20 percent.
- Fourth quarter Permian production of 82,600 barrels of oil equivalent per day (BOE/d), significantly exceeding the original 2017 target of 75,000 BOE/d; fourth quarter
Montneyliquids production more than doubled from the fourth quarter 2016 to 29,000 barrels per day (bbls/d).
- Replaced 168 percent of full-year 2017 production on a Canadian protocols proved plus probable reserves basis after royalties (2P reserves) and 228 percent on an
SECproved reserves basis ( U.S.protocols), excluding dispositions.
- Permian and
Montneytogether replaced 331 percent of their full-year 2017 production on a Canadian protocols 2P reserves basis and 339 percent on an SECproved reserves basis, excluding dispositions.
"We delivered very strong financial and operational results in 2017," said
"We have further demonstrated our confidence in our five-year plan and our commitment to shareholder returns with the announcement of our share repurchase program which we plan to fund with cash on hand," added Suttles. "We are firmly on track to deliver quality returns and compelling growth through our five-year plan and we see strong financial upside."
Innovation, efficiency and commercial ingenuity drive well performance and value
Encana's strong and consistent performance is driven by a relentless focus on innovation and efficiency. The company's large-scale cube development model, high-intensity completions and precision targeting continue to maximize margin, resource recovery and capital efficiency. These innovations increased average 180-day initial production rates by over 25 percent for only 9 percent additional cost.
Operational highlights include:
Permian: strong finish to 2017 sets stage for significant 2018 production growth
- Cube development, advanced completions and precision targeting continue to drive well productivity, efficiencies and returns.
- 2017 total production averaged 66,200 BOE/d, up 37 percent from 2016. Total production in 2018 is expected to increase by approximately 30 percent from 2017.
- Fourth quarter 2017 liquids production more than doubled from the fourth quarter of 2016 to 29,000 bbls/d. This is expected to double again in the fourth quarter of 2018 to between 55,000 and 65,000 bbls/d.
Montneycondensate receives premium pricing similar to WTI. Encanahas diversified the markets for its Western Canadian gas with only four percent of total expected company revenue exposed to AECOin 2018 and approximately five percent in 2019 and 2020.
- Enhanced completion designs continue to drive productivity improvements. These plays averaged total combined production of 67,800 BOE/d in 2017 which was consistent with 2016.
- Both assets delivered free operating cash flow in 2017 and are expected to deliver significant free operating cash flow again in 2018.
2017 year-end and fourth quarter results: driving quality growth and quality returns
Discipline, innovation and efficiency: lowering costs and maintaining a strong balance sheet
At year-end 2017,
2018 capital and production guidance: disciplined capital allocation, liquids growth and margin expansion
Managing risk and maximizing realized price
For 2019, the company has hedged approximately 15,000 bbls/d of expected oil and condensate production at an average price of
The company has announced plans to repurchase up to
|Non-GAAP Cash Flow Reconciliation|
| (for the period ended
($ millions, except per share amounts)
|Cash from (used in) operating activities||369||199||1,050||625|
|Deduct (add back):|
|Net change in other assets and liabilities||(13||)||(11||)||(40||)||(26||)|
|Net change in non-cash working capital||(62||)||(92||)||(253||)||(187||)|
|Non-GAAP cash flow1||444||302||1,343||838|
|Non-GAAP cash flow margin1||14.40||10.21||11.75||6.49|
|Non-GAAP Operating Earnings Reconciliation|
|Net earnings (loss)||(229||)||(281||)||827||(944||)|
|Before-tax (addition) deduction:|
|Unrealized gain (loss) on risk management||46||(149||)||442||(614||)|
|Non-operating foreign exchange gain (loss)||(19||)||(104||)||281||135|
|Gain (loss) on divestitures||(1||)||(3||)||404||390|
|Gain on debt retirement||-||-||-||89|
|After-tax (addition) deduction||(343||)||(366||)||405||(1,020||)|
| Non-GAAP operating earnings (loss) 1
1 Non-GAAP cash flow, non-GAAP cash flow margin and non-GAAP operating earnings are non-GAAP measures as defined in Note 1.
(for the period ended
|NGLs - Plant Condensate (Mbbls/d)||33.7||19.9||69||26.3||20.3||30|
|Oil & Plant Condensate (Mbbls/d)||118.7||86.3||38||102.6||94.0||9|
|NGLs - Other (Mbbls/d)||33.9||22.6||50||26.5||28.1||(6||)|
|Oil and NGLs Total (Mbbls/d)||152.6||108.9||40||129.1||122.1||6|
|Natural gas (MMcf/d)||1,096||1,276||(14||)||1,104||1,383||(20||)|
|Total production (MBOE/d)||335.2||321.5||4||313.2||352.7||(11||)|
|Liquids and Natural Gas Prices|
|Q4 2017||Q4 2016||2017||2016|
|Encana realized liquids prices1|
|NGLs - Plant Condensate||52.65||45.39||48.92||39.84|
|NGLs - Other||24.29||17.86||20.63||12.35|
|Encana realized natural gas price1 ($/Mcf)||2.34||2.35||2.42||2.10|
1 Prices include the impact of realized gain (loss) on risk management.
Year-End 2017 Reserves Estimates
|2017 Reserves Estimates - Canadian Protocols (Net, After Royalties)1|
Using forecast prices and costs; simplified table
| Total as of
|2017 Proved Reserves Estimates - Canadian Protocols (Net, After Royalties)1|
|Using forecast prices and costs; simplified table.||Oil & NGLs
| December 31, 2016
Revisions and economic factors
Extensions, improved recovery and discoveries
|December 31, 2017||386.7||2,848||861.5|
|2017 Proved Reserves Estimates -
|Using constant prices and costs; simplified table.||Oil & NGLs
| December 31, 2016
Revisions and improved recovery
Extensions and discoveries
Purchase of reserves in place
Sale of reserves in place
1 Numbers may not add due to rounding.
Differences between estimates under Canadian and
Estimated Risked Economic Contingent Resources
| Net (after royalties) using
forecast prices and costs.
|Estimated Risked Economic Contingent Resources (MMBOE) 1|
| Contingent Resource
|Canadian Operations||Development Pending||1,152||2,145||2,546|
|Development On Hold||2||2||3|
|USA Operations||Development Pending||1,147||1,375||1,510|
|Development On Hold||13||15||17|
| Total as of December
|Development On Hold||15||17||19|
1 Numbers may not add due to rounding.
For information on reserves and economic contingent resources, see Advisory Regarding Oil and Gas Information.
Conference call information
A conference call and webcast to discuss the 2017 fourth quarter and year-end results will be held for the investment community today at
NOTE 1: Non-GAAP measures
Certain measures in this news release do not have any standardized meaning as prescribed by
- Non-GAAP Cash Flow is a non-GAAP measure defined as cash from (used in) operating activities excluding net change in other assets and liabilities, net change in non-cash working capital and current tax on sale of assets. Non-GAAP Cash Flow Margin is a non-GAAP measure defined as Non-GAAP Cash Flow per BOE of production.
- Non-GAAP Operating Earnings (Loss) is a non-GAAP measure defined as net earnings (loss) excluding non-recurring or non-cash items that management believes reduces the comparability of the company's financial performance between
periods. These items may include, but are not limited to, unrealized gains/losses on risk management, impairments, restructuring charges, non-operating foreign exchange gains/losses, gains/losses on divestitures and gains on debt retirement.
Income taxes may include valuation allowances and the provision related to the pre-tax items listed, as well as income taxes related to divestitures and
U.S.tax reform, and adjustments to normalize the effect of income taxes calculated using the estimated annual effective income tax rate.
- Operating Cash Flow is a non-GAAP measure defined as product revenues less costs associated with delivering the product to market, including production, mineral and other taxes, transportation and processing and operating expenses. Operating Cash Flow is used by management as an internal measure of the profitability of a play(s). Free Operating Cash Flow is a non-GAAP measure defined as Operating Cash Flow in excess of capital investment, excluding net acquisitions and divestitures.
NOTE 2: Information on reserves reporting - Detailed Canadian protocol disclosure will be contained in Encana's Form 51-101F1 for the year ended
ADVISORY REGARDING OIL AND GAS INFORMATION - All estimates in this news release are effective as of
Reserves are the estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, from a given date forward, based on: analysis of drilling, geological, geophysical and engineering data, the use of established technology, and specified economic conditions, which are generally accepted as being reasonable. Proved reserves are those reserves which can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. There is a 10% probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves.
Contingent resources do not constitute, and should not be confused with, reserves. Contingent resources are defined as those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. There is a range of uncertainty of estimated recoverable volumes. A low estimate (1C) is considered to be a conservative estimate of the quantity that will actually be recovered. It is likely that the actual remaining quantities recovered will exceed the low estimate, which under probabilistic methodology reflects at least a 90% confidence level. A best estimate (2C) is considered to be a realistic estimate of the quantity that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate, which under probabilistic methodology reflects at least a 50% confidence level. A high estimate (3C) is considered to be an optimistic estimate. It is unlikely that the actual remaining quantities recovered will exceed the high estimate, which under probabilistic methodology reflects at least a 10% confidence level. There is uncertainty that it will be commercially viable to produce any portion of the resources.
All of the resources classified as contingent are considered to be discovered, and as such have been assigned a 100% chance of discovery, but have however been risked for the chance of development. The chance of development is defined as the likelihood
of a project being commercially viable and development proceeding in a timely fashion. Determining the chance of development requires taking into consideration each contingency and quantifying the risks into an overall development risk factor at a
project level. All of the contingent resources disclosed herein are classified as either Development Pending or Development On Hold. Development Pending is where resolution of the final conditions for development is being actively pursued (high chance
of development). Resources classified in this sub-category must be economic and have been assigned a chance of development ranging between 80 percent and 99 percent. Development On Hold is where there is a reasonable chance of development, but there
are major non-technical contingencies to be resolved that are usually beyond the control of the operator. Resources classified in this sub-category must be economic and have been assigned a chance of development ranging between 50 percent and 79 percent.
Contingent resources are defined as "economic contingent resources" if they are currently economically recoverable and are categorized as economic if those contingent resources have a positive net present value under currently forecasted
prices and costs. In examining economic viability, the same fiscal conditions have been applied as in the estimation of
The conversion of natural gas volumes to barrels of oil equivalent (BOE) is on the basis of six thousand cubic feet to one barrel. BOE is based on a generic energy equivalency conversion method primarily applicable at the burner tip and does not represent economic value equivalency at the wellhead. Readers are cautioned that BOE may be misleading, particularly if used in isolation. 30-day initial or peak production and other short-term rates are not necessarily indicative of long-term performance or of ultimate recovery.
ADVISORY REGARDING FORWARD-LOOKING STATEMENTS - This news release contains certain forward-looking statements or information (collectively, "FLS") within the meaning of applicable securities legislation, including the United States Private Securities Litigation Reform Act of 1995. FLS include: expectation of meeting or exceeding targets in corporate guidance and five-year plan; ability to generate growth, returns, significant financial upside and anticipated shareholder returns; anticipated share repurchase program, including amount and number of shares to be acquired, source of funding, anticipated timeframe, regulatory filings and approval thereof, method and location of purchases, commitment to capital discipline, and reasons and benefits of the program; projected cash available; anticipated capital program, including funding within expected cash flows and allocation thereof; success of and benefits from innovation, including cube development approach, high-intensity completions and precision well targeting; ability to capture cost efficiencies and secure field services and materials; anticipated production, including percentage from core assets, well productivity, efficiencies, returns, margin expansion, product types, delivery of significant free operating cash flow and growth between periods, including impact of commodity prices; exposure to certain commodity prices; ability to maintain a strong balance sheet, including access to sources of liquidity; anticipated hedging and outcomes of risk management program, including amount of hedged production; performance relative to peers; and anticipated dividends
Readers are cautioned against unduly relying on FLS which, by their nature, involve numerous assumptions, risks and uncertainties that may cause such statements not to occur, or results to differ materially from those expressed or implied. These assumptions
include: future commodity prices and differentials; foreign exchange rates; ability to access credit facilities and shelf prospectuses; assumptions contained in the Company's corporate guidance, five-year plan and as specified herein; data contained
in key modeling statistics; availability of attractive hedges and enforceability of risk management program; effectiveness of
Risks and uncertainties that may affect these business outcomes include: ability to generate sufficient cash flow to meet obligations; commodity price volatility; ability to secure adequate transportation and potential pipeline curtailments; variability
and discretion of
Further information on
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