News
-- fourth quarter production from core assets of 237,100 barrels of oil
equivalent per day (BOE/d), representing 74 percent of total production
-- fourth quarter total liquids production of 108,900 barrels per day
(bbls/d) including oil and plant condensate production of 86,300 bbls/d,
representing almost 80 percent of total liquids production
-- fourth quarter cash from operating activities of $199 million and non-
GAAP cash flow of $302 million
-- lowered full-year average drilling and completion costs by about 30
percent compared to 2015
-- drove further efficiency across the business, delivering more than $600
million of savings compared to 2015
-- reduced long-term debt by $1.1 billion from 2015 and net debt by more
than 50 percent since year-end 2014
-- generated full-year cash from operating activities of $625 million and
non-GAAP cash flow of $838 million
-- replaced 326 percent of full-year 2016 production on a proved plus
probable reserves basis after royalties (Canadian protocols) and 175
percent of full-year 2016 production on an SEC proved reserves basis
(U.S. protocols), excluding dispositions
"We delivered on our 2016 strategic objectives and our performance through the fourth quarter created a powerful launch pad for our five-year growth plan," said
"We carried considerable momentum into 2017," added Suttles. "Through innovation and our relentless focus on efficiency and supply chain management, we expect to hold total year-over-year drilling and completion costs flat despite cost inflation for some services. We expect to significantly increase crude and condensate production throughout the year and deliver strong corporate margin growth."
Better wells at lower cost
-- In the Permian,Encana's latest completion designs are delivering strong well performance. Two new Midland County wells delivered average 30-day initial production rates of 1,200 BOE/d, including 900 bbls/d of oil. Two new Howard County wells averaged 30-day initial production rates of about 1,200 BOE/d, including approximately 1,050 bbls/d of oil. During the fourth quarter,Encana maintained its leading drilling and completions costs to deliver average normalized drilling and completion costs of$5 million per well. Average full-year 2016 normalized drilling and completion costs were 30 percent lower than in 2015. The company grew total 2016 production by 20 percent compared to 2015. In 2017,Encana aims to grow value and improve well productivity through optimized completion designs, which have the potential to further expand its premium return well inventory. The company expects to grow production by approximately 50 percent from the fourth quarter of 2016 to the fourth quarter of 2017. -- In the Eagle Ford, the company used optimized completion designs on three newEagle Ford wells which out-performed expectations, delivering average 90-day initial production rates of 1,450 BOE/d.Encana's newestAustin Chalk well delivered a 30-day initial production rate of 1,000 BOE/d. This latest well is approximately 25 miles from the first two wells, indicatingAustin Chalk potential across a sizable portion ofEncana's acreage.Encana has added an additional 50 premium return wells to itsEagle Ford inventory. Average 2016 normalized drilling and completion costs were 23 percent lower than in 2015. In 2017,Encana plans to drill between 10 and 15 Austin Chalk wells. The company is focused on enhancing well performance through new completion designs across the play and believes there is potential to further expand its premium return well inventory. -- In theMontney , the company delivered a 50 percent well productivity improvement from a new well by applying a completion design similar to one successfully pioneered in the Eagle Ford 12 weeks earlier.Encana continues to ramp up activity in theCutbank Ridge area of the play in preparation for two midstream processing plants becoming operational in the fourth quarter of 2017. Construction for both plants remains on schedule and under budget. The company's average normalized drilling and completion costs in the fourth quarter were$4.4 million per well while average full-year 2016 normalized drilling and completion costs were about 25 percent lower than in 2015.Encana grew total 2016 liquids production by six percent from 2015 (excluding Gordondale). In 2017,Encana will focus on liquids-rich locations where the program is expected to deliver an average 85 barrels of liquids per million cubic feet of gas (bbls/MMcf). The company plans to more than double liquids production from the fourth quarter of 2016 to the fourth quarter of 2017 with condensate expected to make up 85 percent of the production growth. -- In theDuvernay , the company successfully ramped up production through the 10-29 processing facility which was brought online in mid-2016. Two new wells in the volatile oil window are exceeding expectations and delivered 60-day initial production rates of about 1,500 BOE/d with nearly 1,000 bbls/d of condensate.Encana grew total 2016 production by 86 percent compared to 2015. Average 2016 normalized drilling and completion costs were 45 percent lower than in 2015. Throughout 2017,Encana will assess the potential for premium return drilling inventory expansion in the volatile oil window and delineate the stacked pay potential of theMontney zone within the play.
Lower costs, lower debt and significant liquidity
2016 fourth quarter and year-end results During the fourth quarter of 2016,
2017 capital and production guidance: Delivering efficient growth
With its premium return well inventory, expected growth in crude and condensate production and cost efficiencies,
Dividend declared OnFebruary 15, 2017 , the Board declared a dividend of$0.015 per share payable onMarch 31, 2017 to common shareholders of record as ofMarch 15, 2017 . ---------------------------------------------------------------------------- Non-GAAP Cash Flow Reconciliation ---------------------------------------------------------------------------- (for the period ended December 31) ($ millions, except per share Q4 Q4 amounts) 2016 2015 2016 2015 ---------------------------------------------------------------------------- Cash from (used in) operating 199 448 625 1,681 activities Deduct (add back): Net change in other assets and liabilities (11) 7 (26) (11) Net change in non-cash working capital (92) 58 (187) 262 ---------------------------------------------------------------------------- Non-GAAP cash flow1 302 383 838 1,430 ---------------------------------------------------------------------------- Non-GAAP Operating Earnings Reconciliation ---------------------------------------------------------------------------- Net earnings (loss) (281) (612) (944) (5,165) Before-tax (addition) deduction: Unrealized gain (loss) on risk management (149) (90) (614) (331) Impairments - (805) (1,396) (6,473) Non-operating foreign exchange gain (loss) (104) (106) 135 (776) Restructuring charges (1) (5) (34) (64) Gain (loss) on divestitures (3) - 390 14 Gain on debt retirement - - 89 - ---------------------------------------------------------------------------- (257) (1,006) (1,430) (7,630) Income tax (109) 283 410 2,526 ---------------------------------------------------------------------------- After-tax (addition) deduction (366) (723) (1,020) (5,104) ---------------------------------------------------------------------------- Non-GAAP operating earnings 85 111 76 (61) (loss) (1) Non-GAAP operating earnings (loss) per share 0.09 0.13 0.09 (0.07) ----------------------------------------------------------------------------
(1) Non-GAAP cash flow and non-GAAP operating earnings are non-GAAP measures as defined in Note 1.
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Production Summary
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(for the period ended December 31) Q4 Q4
(average) 2016 2015 % ∆ 2016 2015 % ∆
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Natural gas (MMcf/d) 1,276 1,571 (19) 1,383 1,635 (15)
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Oil and NGLs (Mbbls/d) 108.9 145.0 (25) 122.1 133.4 (8)
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Total production (MBOE/d) 321.5 406.8 (21) 352.7 405.9 (13)
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Natural Gas and Liquids Prices
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Q4 2016 Q4 2015 2016 2015
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Natural gas
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NYMEX ($/MMBtu) 2.98 2.27 2.46 2.66
Encana realized natural gas price(1)
($/Mcf) 2.35 3.43 2.10 3.89
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Oil and NGLs($/bbl)
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WTI 49.29 42.18 43.32 48.80
Encana realized liquids price(1) 42.96 39.11 38.85 39.93
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(1) Prices include the impact of realized gain (loss) on risk management.
Year-End 2016 Reserves Estimates
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2016 Reserves Estimates - Canadian Protocols (Net, After Royalties)(1)
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Using forecast prices and costs; 3P
simplified table 2P Proved +
1P Proved + Probable +
(MMBOE) Proved Probable Possible
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Canadian Operations 481 1,213 1,469
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USA Operations 439 825 903
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Total as of December 31, 2016 920 2,038 2,372
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2016 Proved Reserves Estimates - Canadian Protocols (Net, After
Royalties)(1)
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Using forecast prices and costs; Natural Gas Oil & NGLs Total
simplified table. (Bcf) (MMbbls) (MMBOE)
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December 31, 2015 4,076 380.1 1,059.5
Extensions, improved recovery and
discoveries 515 75.9 161.8
Revisions and economic factors (149) (17.5) (42.2)
Acquisitions 17 13.0 15.9
Dispositions (427) (75.0) (146.1)
Production (506) (44.7) (129.1)
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December 31, 2016 3,527 332.0 919.9
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---------------------------------------------------------------------------- 2016 Proved Reserves Estimates -U.S. Protocols (Net, After Royalties)(1) ---------------------------------------------------------------------------- Using constant prices and costs; Natural Gas Oil & NGLs Total simplified table. (Bcf) (MMbbls) (MMBOE) ---------------------------------------------------------------------------- December 31, 2015 3,064 288.8 799.4 Revisions and improved recovery (244) (23.9) (64.7) Extensions and discoveries 887 128.0 275.7 Purchase of reserves in place 16 12.2 14.9 Sale of reserves in place (313) (54.4) (106.5) Production (506) (44.7) (129.1) ---------------------------------------------------------------------------- December 31, 2016 2,902 306.0 789.7 ----------------------------------------------------------------------------
(1) Numbers may not add due to rounding.
Differences between estimates under Canadian and
Estimated Risked Economic Contingent Resources
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Net (after royalties) using Estimated Risked Economic Contingent Resources
forecast prices and costs. (MMBOE)
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Contingent 1C 2C 3C
Resource Low Best High
Sub-class estimate estimate estimate
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Development
Canadian Operations Pending 1,502 1,876 2,235
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Development
On Hold 25 38 48
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Development
USA Operations Pending 1,513 1,721 1,920
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Development
On Hold 257 653 804
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Total as of December 31, Development
2016 Pending 3,015 3,597 4,155
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Development
On Hold 282 691 852
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For information on reserves and economic contingent resources, see Advisory Regarding Reserves & Other Resources Information.
Conference call information
Important Information Encana reports in
NOTE 1: Non-GAAP measures
This news release contains references to non-GAAP measures as follows:
-- Non-GAAP Cash flow is a non-GAAP measure defined as cash from operating
activities excluding net change in other assets and liabilities, net
change in non-cash working capital and current tax on sale of assets.
Corporate 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
adjustments to normalize the effect of income taxes calculated using the
estimated annual effective income tax rate.
-- Net Debt is a non-GAAP measure defined as long-term debt, including the
current portion, less cash and cash equivalents. Management uses this
measure as a substitute for total long-term debt in certain internal
debt metrics as a measure of the company's ability to service debt
obligations and as an indicator of the company's overall financial
strength.
NOTE 2: Information on reserves reporting - Detailed Canadian protocol disclosure will be contained in
ADVISORY REGARDING RESERVES & OTHER RESOURCES 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.
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. 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 percent 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 percent 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 percent 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 percent 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 in the above table 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 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.
Drilling and completions costs in the Permian,
ADVISORY REGARDING FORWARD-LOOKING STATEMENTS - This news release contains certain forward-looking statements or information (collectively, "FLS") within the meaning of applicable securities legislation. FLS include: expected growth in corporate margin and crude and condensate production; anticipated value creation and growth in 2017; achieving metrics in
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;
Risks and uncertainties that may affect these business outcomes include: the ability to generate sufficient cash flow to meet
Although
SOURCE:
FOR FURTHER INFORMATION PLEASE CONTACT:
Further information on
Investor contact:Brendan McCracken Vice-President, Investor Relations (403) 645-2978Patti Posadowski Sr. Advisor, Investor Relations (403) 645-2252 Media contact:Simon Scott Vice-President, Communications (403) 645-2526Jay Averill Director, Media Relations (403) 645-4747 Source:Encana Corporation