Encana delivered strong performance across its business in the fourth quarter, positioning itself to create value and return to growth in 2017. Throughout 2016, Encana grew quarter-over-quarter non-GAAP cash flow, significantly lowered costs, strengthened its balance sheet and continued to deliver better wells at lower cost in each of its core assets. The company reached its planned 2017 activity level in the fourth quarter to launch itself into 2017, when it expects to deliver strong growth in crude and condensate production and increase its non-GAAP corporate margin. The company is firmly on track with its five-year plan. Fourth quarter and full-year highlights from 2016 include:
- 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 Doug Suttles, Encana President & CEO. “We drove innovation and efficiency into every part of our business to increase margins and returns and we have one of the largest premium return drilling inventories in our industry. Our high quality multi-basin portfolio and leading operational performance positions us to generate strong returns at today’s prices.”
“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
Encana’s focus on operational excellence, stacked pay zones and developing its premium return well inventory has positioned the company as an operational leader in each of its core assets. In 2016, Encana had 10,000 premium return well locations and the company anticipates growing that inventory through 2017. Already in 2017, Encana has added 50 premium return well locations to its Eagle Ford inventory. Harnessing the competitive advantages of its high quality multi-basin portfolio, Encana rapidly applies technical advancements and efficiencies across its core assets to deliver better wells at lower cost. Highlights in 2016 include:
- 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 new Eagle Ford wells which out-performed expectations, delivering average 90-day initial production rates of 1,450 BOE/d. Encana’s newest Austin 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, indicating Austin Chalk potential across a sizable portion of Encana’s acreage. Encana has added an additional 50 premium return wells to its Eagle 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 the Montney, 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 the Cutbank 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 the Duvernay, 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 the Montney zone within the play.
Lower costs, lower debt and significant liquidity
Encana delivered over $600 million in cost efficiencies compared to 2015. The company reduced its long-term debt by $1.1 billion through 2016. At year-end, long-term debt totalled approximately $4.2 billion and net debt was about $3.4 billion. Encana concluded 2016 with approximately $5.3 billion of liquidity made up of $4.5 billion in available credit facilities and cash and cash equivalents of $834 million on its balance sheet, compared to cash and cash equivalents of $271 million at year-end 2015.
2016 fourth quarter and year-end results
During the fourth quarter of 2016, Encana delivered cash from operating activities of $199 million and non-GAAP cash flow of $302 million or $0.31 per share. Full-year 2016 cash from operating activities was $625 million and non-GAAP cash flow was $838 million or $0.95 per share.
Encana reported a fourth quarter net loss of $281 million, or $0.29 per share, and a full-year net loss of $944 million, or $1.07 per share, including $938 million of after-tax, non-cash ceiling test impairments, a net loss on risk management and a deferred tax valuation allowance, partially offset by gains on divestitures and foreign exchange. Fourth quarter non-GAAP operating earnings were $85 million, or $0.09 per share. Full-year non-GAAP operating earnings were $76 million, or $0.09 per share.
Encana’s core assets contributed 74 percent of total fourth quarter production of 321,500 BOE/d and 72 percent of the full-year average of 352,700 BOE/d. Full-year liquids production averaged 122,100 bbls/d representing approximately 35 percent of the company’s production mix. Encana expects to grow liquids volumes to over 40 percent of total production in the fourth quarter of 2017. Natural gas production in 2016 averaged 1,383 million cubic feet per day (MMcf/d).
2017 capital and production guidance: Delivering efficient growth
Encana’s 2017 capital program is expected to be between $1.6 billion and $1.8 billion. Total production is expected to be between 320,000 BOE/d and 330,000 BOE/d. Encana plans to grow crude and condensate production by more than 35 percent through 2017 and production from its core assets by more than 20 percent from the fourth quarter of 2016 to the fourth quarter of 2017. The company estimates total liquids volumes will average between 125,000 bbls/d and 130,000 bbls/d with natural gas production between 1,150 MMcf/d to 1,200 MMcf/d.
With its premium return well inventory, expected growth in crude and condensate production and cost efficiencies, Encana expects to deliver a corporate margin of greater than $10 per barrel of oil equivalent (BOE) in 2017. Encana plans to fund its 2017 capital program with cash flows and cash on hand. Encana’s 2017 guidance can be downloaded from the company’s website at http://www.encana.com/investors/financial/corporate-guidance.html.
Encana updates its risk management program
The combination of Encana’s multi-basin portfolio, 100 percent short-cycle capital program and robust hedge strategy uniquely positions the company to effectively manage risk.
Encana enters 2017 with a strong risk management position to significantly mitigate commodity price uncertainty. As at January 31, 2017, Encana had hedged approximately 79,000 bbls/d of expected 2017 crude and condensate production for the balance of the year using a variety of structures at an average price of $53.56 per barrel. In addition, the company has hedged about 860 MMcf/d of expected 2017 natural gas production for the balance of the year using a variety of structures at an average price of $3.13 per thousand cubic feet (Mcf).
On February 15, 2017, the Board declared a dividend of $0.015 per share payable on March 31, 2017 to common shareholders of record as of March 15, 2017.
|Non-GAAP Cash Flow Reconciliation|
|(for the period ended December 31)
($ millions, except per share amounts)
|Cash from (used in) operating activities||199
|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)
|Before-tax (addition) deduction:|
|Unrealized gain (loss) on risk management||(149)||(90)||(614)||(331)|
|Non-operating foreign exchange gain (loss)||(104)||(106)||135||(776)|
|Gain (loss) on divestitures||(3)||–||390||14|
|Gain on debt retirement||–||–||89||–|
|After-tax (addition) deduction||(366)||(723)||(1,020)||(5,104)|
|Non-GAAP operating earnings (loss) 1||85
|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.
|(for the period ended December 31)
|% ∆||2016||2015||% ∆|
|Natural gas (MMcf/d)||1,276||1,571||(19)||1,383||1,635||(15)|
|Oil and NGLs (Mbbls/d)||108.9||145.0||(25)||122.1||133.4||(8)|
|Total production (MBOE/d)||321.5||406.8||(21)||352.7||405.9||(13)|
|Natural Gas and Liquids Prices|
|Q4 2016||Q4 2015||2016||2015|
|Encana realized natural gas price1 ($/Mcf)||2.35||3.43||2.10||3.89|
|Oil and NGLs($/bbl)|
|Encana realized liquids price1||42.96||39.11||38.85||39.93|
1 Prices include the impact of realized gain (loss) on risk management.
Year-End 2016 Reserves Estimates
|2016 Reserves Estimates – Canadian Protocols (Net, After Royalties)1|
|Using forecast prices and costs; simplified table
|Total as of December 31, 2016||920||2,038||2,372|
|2016 Proved Reserves Estimates – Canadian Protocols (Net, After Royalties)1|
|Using forecast prices and costs; simplified table.||Natural Gas
|Oil & NGLs
|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)|
|December 31, 2016||3,527||332.0||919.9|
|2016 Proved Reserves Estimates – U.S. Protocols (Net, After Royalties)1|
|Using constant prices and costs; simplified table.||Natural Gas
|Oil & NGLs
|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)|
|December 31, 2016||2,902||306.0||789.7|
1 Numbers may not add due to rounding.
Encana replaced 326 percent of full-year 2016 production on an NI 51-101 (Canadian protocol) proved plus probable reserves basis after royalties and 175 percent of full-year 2016 production on an SEC (U.S. protocol) proved reserves basis, excluding dispositions. The changes were primarily due to Encana’s continued execution and increased investment in its core assets.
Differences between estimates under Canadian and U.S. protocols primarily represent the use of forecast prices in the estimation of reserves under Canadian standards, while U.S. standards require the use of 12-month average historical prices which are held constant. For information on reserves reporting, see Note 2.
Estimated Risked Economic Contingent Resources
|Net (after royalties) using forecast prices and costs.||Estimated Risked Economic Contingent Resources (MMBOE)|
|Contingent Resource Sub-class||1C
|Canadian Operations||Development Pending||1,502||1,876||2,235|
|Development On Hold||25||38||48|
|USA Operations||Development Pending||1,513||1,721||1,920|
|Development On Hold||257||653||804|
|Total as of December 31, 2016||Development Pending||3,015||3,597||4,155|
|Development On Hold||282||691||852|