U.S. SECURITIES AND EXCHANGE
COMMISSION
Washington, D.C. 20549
FORM 6-K
Report of
Foreign Private Issuer
Pursuant to Rule 13a-16 or 15d-16
under the Securities Exchange Act of 1934
For November 18, 2015
Commission File Number: 1-15226
ENCANA
CORPORATION
(Translation of registrants name into English)
Suite 4400, 500 Centre Street SE
PO Box 2850
Calgary,
Alberta, Canada T2P 2S5
(Address of principal executive office)
Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F:
Form
20-F ¨ Form 40-F þ
Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1): ¨
Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T
Rule 101(b)(7): ¨
DOCUMENTS FILED AS PART OF THIS FORM 6-K
See the Exhibit Index to this Form 6-K.
SIGNATURES
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.
Date: November 18, 2015
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ENCANA CORPORATION |
(Registrant) |
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By: |
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/s/ Dawna I. Gibb |
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Name: |
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Dawna I. Gibb |
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Title: |
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Assistant Corporate Secretary |
Form 6-K Exhibit Index
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Exhibit No. |
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99.1 |
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Interim Report to Shareholders for the period ended September 30, 2015, including the Unaudited Interim Condensed Consolidated Financial Statements and Managements Discussion and Analysis for the said period. |
2015 Q3 Report
For the period ended
September 30, 2015
encana
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news release |
Encana lowers costs and grows high margin production in the third quarter
Calgary, Alberta (November 12, 2015) TSX, NYSE: ECA
Encana continued to grow high margin production in each of its core four assets during the third quarter and took further decisive steps to lower its
cost structures, manage its balance sheet and focus its portfolio. Highlights include:
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liquids production up 10 percent from the second quarter and 35 percent year-over-year to 140,400 barrels per day (bbls/d), marking an eighth consecutive
quarter of liquids growth |
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production from the companys core four assets, the Permian, Eagle Ford, Duvernay and Montney, increased 12 percent over the second quarter to 249,300
barrels of oil equivalent per day (BOE/d) |
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cash flow increased by $190 million from the second quarter to $371 million |
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disciplined capital allocation with over 90 percent of capital invested in the companys core four assets |
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reduced Permian horizontal drilling and completions costs by $2.0 million per well and Eagle Ford drilling and completion costs by $2.4 million per well
since acquiring positions in both plays last year |
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announced agreements in August and October to divest its Haynesville and DJ Basin assets for a total cash consideration of $1.75 billion before closing
adjustments; proceeds will be used to further strengthen the balance sheet and provide greater financial flexibility |
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under the agreement to sell its Haynesville natural gas assets (effective date of January 1, 2015), Encana will reduce its gathering and midstream
commitments by $480 million on an undiscounted basis |
During the third quarter all aspects of our strategy came together to
drive performance and deliver value, said Doug Suttles, President & CEO. Disciplined capital allocation in our core four assets, combined with fast-paced operational innovation, delivered sustainable performance improvements and
grew high-margin, high-return liquids volumes, which helped offset the quarter-over-quarter impact of lower liquids prices.
Total company
production in the quarter averaged 398,300 BOE/d with Encanas core four assets, the Permian, Eagle Ford, Duvernay and Montney, contributing 249,300 BOE/d or 63 percent. Third quarter liquids production was 140,400 bbls/d, up 10 percent from
the second quarter and 35 percent year-over-year, marking an eighth consecutive quarter of liquids growth. Natural gas volumes averaged 1,547 million cubic feet per day (MMcf/d).
Decisive action across the organization is continuously strengthening our business, said Suttles. We are capturing the benefits of an
increasingly focused portfolio and disciplined capital program, as well as significant reductions in our cost structures, debt and interest expense. Encana is competitively positioned, delivering strong returns in todays price environment with
tremendous torque to any uplift in oil prices.
Since launching its strategy two years ago, Encana has driven down corporate costs, such as
interest and administrative expenses, by about $300 million per year. Excluding one-time interest payments on the early redemption of debt, interest expense has been reduced by $150 million per year over that time. These proactive cost reductions,
combined with $2.8 billion in announced and completed divestitures and a C$1.44 billion bought deal offering in 2015, will strengthen the balance sheet and provide greater financial flexibility. Pending the closing of previously announced
divestitures, by year-end 2015 Encana expects to have reduced debt by around $2.8 billion with no long-term debt maturities until 2019.
Encana
remains on track to deliver its 2015 cash flow guidance of between $1.4 billion and $1.6 billion. The company generated third quarter cash flow of $371 million or $0.44 per share, up $190 million from the second quarter when Encana made a $165
million one-time outlay associated with the early redemption of long-term debt. This early debt redemption is expected to save Encana $200 million in gross interest expense.
In the third quarter, the company reported an operating loss of $24 million or $0.03 per share; and a net loss of $1.2 billion or $1.47 per share
primarily due to a $1.1 billion non-cash, after-tax ceiling test impairment. Year-to-date, Encana has generated $1.0 billion in cash flow or $1.29 per share; an operating loss of $172 million or $0.21 per share; and a net loss of $4.6 billion or
$5.59 per share, largely attributable to non-cash, after-tax ceiling test impairments of $3.6 billion.
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Encana Corporation |
Innovation is part of our culture and crucial to value creation, added Suttles. Our
decision to invest in operational innovation, particularly in the Permian, has delivered rapid and sustainable performance improvements and invaluable technical insight. Our continuous testing of well spacing, completions design and simultaneous
operations is driving down costs, delivering better wells and helping us quickly discover optimal well designs in each of our core four assets.
To carry operational momentum into 2016, Encana has chosen to accelerate activity in the Permian originally scheduled for 2016 into the fourth quarter
of this year, increasing its 2015 investment in the play by $150 million. Encana expects to conclude the year around the upper end of its 2015 capital guidance range of $2.2 billion.
Operating highlights:
Permian: Top tier operator after only 10
months in play
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continued success in reducing drilling and completion costs, which are down $2.0 million per well in less than a year since entering the play |
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drilled latest pace-setting well in the Wolfcamp with a cycle time of 14 days |
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successful continuation of simultaneous operations with frac plugs drilled out on four wells simultaneously on the same pad |
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ran six 24-hour frac crews simultaneously over 10 days on six multi-well pads |
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drilled 17 net horizontal wells and 27 net vertical wells and brought 28 net horizontal wells and 30 net vertical wells on production |
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third quarter production of 45,700 BOE/d, up 28 and 42 percent from the second and first quarters respectively |
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expect to drill 36 net wells and bring 30 on production in the fourth quarter |
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on track to deliver fourth quarter production of 50,000 BOE/d |
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returns averaging more than 30 percent in 2015 based on October strip pricing |
Eagle Ford: A great asset
continues to outperform
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continued success in reducing drilling and completion costs, which are down $2.4 million per well since entering the play in June 2014 |
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completed upgrades to Patton Trust North facility, which when combined with the second quarter upgrades at Patton Trust South, increased gross production capacity by 30,000 bbls/d |
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drilled 10 net wells and brought 29 net wells on production |
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third quarter production of 54,000 BOE/d, up 18 and 29 percent from the second and first quarters respectively |
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expect to drill 14 net wells and bring seven on production in the fourth quarter |
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on track to deliver fourth quarter production of 57,000 BOE/d |
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returns averaging more than 30 percent in 2015 based on October strip pricing |
Duvernay: Delivering compelling
returns
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repeated industry-leading drilling and completion costs of $10.4 million per well on the 15-22 multi-well pad |
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brought the 15-31 compressor station online, increasing processing capacity by 10,000 bbls/d and 50 MMcf/d |
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drilled two net wells and brought seven net wells on production |
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third quarter production of 9,300 BOE/d, up 59 and 69 percent from the second and first quarters respectively |
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expect to drill five net wells and bring six on production in the fourth quarter |
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on track to deliver fourth quarter production of 17,000 BOE/d |
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returns averaging more than 30 percent in 2015 (excluding joint venture carry) based on October strip pricing |
Montney: Capital efficiency and continued liquids growth
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strong liquids production in the Tower area, with four wells each flowing at more than 500 bbls/d of condensate within the first 30 days |
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brought nine net wells on production |
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third quarter production of 140,400 BOE/d, up three percent from the second quarter and comprising 21,800 bbls/d of liquids and 711 MMcf/d of natural gas; third quarter natural gas production was impacted by ongoing
third-party transportation restrictions |
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expect to drill two net wells and bring seven on production in the fourth quarter |
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on track to deliver fourth quarter production of 146,000 BOE/d |
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the company continues to monitor ongoing third-party transportation restrictions to assess potential impact on fourth quarter natural gas production |
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returns averaging more than 60 percent in 2015 (excluding third party capital) based on October strip pricing |
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Encana Corporation |
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Additional information on Encanas core four assets will be available in the companys updated
corporate presentation later today. Encanas updated 2015 guidance is available for download from http://www.encana.com/investors/financial/corporate-guidance.html.
Encana updates its risk management program in the quarter
At September 30, 2015, Encana has hedged approximately 1,000 MMcf/d of expected October to December 2015 natural gas production using NYMEX fixed
price contracts at an average price of $4.29 per thousand cubic feet (Mcf) and approximately 95 MMcf/d of expected 2016 natural gas production using fixed price contracts at an average price of $2.98 per Mcf. In addition, Encana has protection on
approximately 300 MMcf/d of expected 2016 natural gas production hedged under three-way costless collars. The NYMEX three-way costless collars are a combination of a sold call, purchased put and a sold put with average prices of $3.43, $3.21 and
$2.72 per Mcf, respectively. 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 partial downside price protection through the combination of the put
options.
At September 30, 2015, Encana has hedged approximately 88.9 thousand barrels per day (Mbbls/d) of expected October to December
2015 oil production using WTI fixed price contracts at an average price of $58.09 per bbl and approximately 38.0 Mbbls/d of expected 2016 oil production at an average price of $62.83 per bbl. Encana also has protection on approximately 18.3 Mbbls/d
of expected 2016 oil production hedged under three-way costless collars. The WTI three-way costless collars are a combination of a sold call, purchased put and a sold put with average prices of $63.03, $55.00 and $47.24 per bbl, respectively.
Dividend declared
On November 11, 2015, Encanas
Board of Directors declared a dividend of $0.07 per share payable on December 31, 2015, to common shareholders of record as of December 15, 2015.
Third Quarter Highlights
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Financial Summary |
(for the period ended
September 30) ($ millions, except per share amounts) |
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Q3
2015 |
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Q3
2014 |
Cash flow1 |
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371 |
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807 |
Per share
diluted |
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0.44 |
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1.09 |
Operating earnings (loss)1 |
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(24) |
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281 |
Per share
diluted |
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(0.03) |
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0.38 |
Earnings
Reconciliation Summary |
Net earnings (loss) attributable to common
shareholders |
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(1,236) |
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2,807 |
After-tax (addition) deduction: |
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Unrealized hedging gain (loss) |
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107 |
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160 |
Impairments |
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(1,066) |
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- |
Restructuring charges |
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(20) |
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(5) |
Non-operating foreign exchange gain (loss) |
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(212) |
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(218) |
Gain (loss) on divestitures |
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(2) |
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2,399 |
Income tax
adjustments |
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(19) |
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190 |
Operating earnings (loss)1 |
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(24) |
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281 |
Per share
diluted |
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(0.03) |
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0.38 |
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1 Cash flow and operating earnings (loss) are non-GAAP measures as defined in Note 1 on page 4. |
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Encana Corporation |
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Production Summary |
(for the period ended
September 30) (After royalties) |
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Q3
2015 |
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Q3
2014 |
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% Δ |
Natural gas
(MMcf/d) |
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1,547 |
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2,199 |
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(30) |
Liquids
(Mbbls/d) |
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140.4 |
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104.0 |
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35 |
Total
production (MBOE/d) |
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398.3 |
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470.6 |
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(15) |
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Natural Gas and Liquids Prices |
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Q3 2015 |
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Q3 2014 |
Natural
Gas |
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NYMEX ($/MMBtu) |
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2.77 |
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4.06 |
Encana realized
gas price1 ($/Mcf) |
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3.71 |
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4.03 |
Oil and Natural
Gas Liquids ($/bbl) |
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WTI |
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46.43 |
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97.17 |
Encana realized oil price1 |
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49.38 |
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90.22 |
Encana realized
NGLs price |
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19.57 |
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48.76 |
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1 Realized prices include the impact of financial hedging. |
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A conference call and webcast to discuss the third quarter 2015 results will be held for the investment community today
at 7 a.m. MT (9 a.m. ET). To participate, please dial (877) 291-4570 (toll-free in North America) or (647) 788-4919 about 10 minutes prior to the conference call. An archived recording of the call will be available from 10 a.m. MT on
November 12 until 9:59 p.m. MT on November 19, 2015 by dialing (800) 585-8367 or (416) 621-4642 and entering passcode 56244231. A live audio webcast of the conference call, including slides, will also be available on
Encanas website, www.encana.com, under Invest In Us/Presentations & Events. The webcasts will be archived for 90 days.
Encana Corporation
Encana is a leading North American
energy producer that is focused on developing its strong portfolio of resource plays, held directly and indirectly through its subsidiaries, producing natural gas, oil and natural gas liquids (NGLs). By partnering with employees, community
organizations and other businesses, Encana contributes to the strength and sustainability of the communities where it operates. Encana common shares trade on the Toronto and New York stock exchanges under the symbol ECA.
Important Information
Encana reports in U.S. dollars unless
otherwise noted. Production, sales and reserves estimates are reported on an after-royalties basis, unless otherwise noted. Per share amounts for cash flow and earnings are on a diluted basis. The term liquids is used to represent oil, NGLs and
condensate. The term liquids-rich is used to represent natural gas streams with associated liquids volumes. Certain production and financial information contained in this news release are presented in approximate figures. Unless otherwise specified
or the context otherwise requires, reference to Encana or to the company includes reference to subsidiaries of and partnership interests held by Encana Corporation and its subsidiaries.
NOTE 1: Non-GAAP measures
This news release contains references to non-GAAP
measures as follows:
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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 cash tax on sale of assets. Free cash flow is a non-GAAP measure defined as cash flow in excess of capital investment, excluding net acquisitions and divestitures, and is used to determine the funds available for other investing
and/or financing activities. |
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Operating earnings (loss) is a non-GAAP measure defined as net earnings (loss) attributable to common shareholders excluding non-recurring or non-cash items
that management believes reduces the comparability of the companys financial performance between periods. These after-tax items may include, but are not limited to, unrealized hedging gains/losses, impairments, restructuring charges,
non-operating foreign exchange gains/losses, gains/losses on divestitures, income taxes related to divestitures and adjustments to normalize the effect of income taxes calculated using the estimated annual effective income tax rate.
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Encana Corporation |
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These measures have been described and presented in this news release in order to provide shareholders and
potential investors with additional information regarding Encanas liquidity and its ability to generate funds to finance its operations. The company believes that the discounted after-tax future net cash flows from proved reserves required to
be used in the ceiling test calculation are not indicative of the fair market value of Encanas natural gas and oil properties or the future cash flows expected to be generated from such properties.
Rates of return for a particular play or well are on a before-tax basis and are based on specified commodity prices with local pricing offsets, capital
costs associated with drilling, completing and equipping a well, the Companys field operating expenses and certain type curve assumptions.
ADVISORY
REGARDING OIL AND GAS INFORMATION
Play is a term used by Encana which encompasses resource plays, geological formations and conventional plays.
Resource play is a term used by Encana to describe an accumulation of hydrocarbons known to exist over a large areal expanse and/or thick vertical section, which when compared to a conventional play, typically has a lower geological and/or
commercial development risk and lower average decline rate.
30-day initial production and other short-term rates are not necessarily indicative of
long-term performance or of ultimate recovery. 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.
The disclosure regarding drilling locations is based on internal estimates. The drilling locations which Encana will actually drill will ultimately
depend upon the availability of capital, regulatory and partner approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors.
ADVISORY REGARDING FORWARD-LOOKING STATEMENTS
This news
release contains certain forward-looking statements or information (collectively, forward-looking statements or FLS) within the meaning of applicable securities legislation. FLS include, but are not limited to: expected
proceeds, including cash consideration, from divestiture transactions, the use of proceeds therefrom, the expectation that the respective closing conditions will be satisfied, the timing of closing thereof and the expected impact on cash flow; the
Companys expectation that it will reduce its gathering and midstream commitments as a result of certain divestitures; expected 2015 capital investment, including increased capital investment in the Permian; expected 2015 cash flow; expected
total reduction in debt and savings in gross interest expense; expected production and number of wells; the ability to manage the balance sheet and continue to improve operational innovation to increase returns and margins; increase in available
production capacity as a result of upgrades to certain facilities; and the expectation of meeting the targets in the Companys 2015 corporate guidance.
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 for results to differ materially from those expressed or implied. These assumptions include, but are not limited to: the ability to satisfy closing conditions, successful closing of, and the value of post-closing and
other adjustments associated with divestiture transactions; the expectation that counterparties will successfully fulfill their obligations under gathering and midstream commitments; assumptions contained in Encanas 2015 corporate guidance and
in this news release; the effectiveness of Encanas resource play hub model to drive productivity and efficiencies; and expectations and projections made in light of, and generally consistent with, Encanas historical experience and its
perception of historical trends, including with respect to the pace of technological development, the benefits achieved and general industry expectation.
Risks and uncertainties that may affect these business outcomes include, but are not limited to: risks inherent to closing announced divestitures and
adjustments that may reduce the expected proceeds and value to Encana; the ability to generate sufficient cash flow to meet the Companys obligations; commodity price volatility; ability to secure adequate product transportation and potential
pipeline curtailments; variability of dividends to be paid; timing and costs of well, facilities and pipeline construction; business interruption and casualty losses or unexpected technical difficulties; counterparty and credit risk associated with
hedging contracts; risk and effect of a downgrade in credit rating, including
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Encana Corporation |
access to capital markets; failure to achieve anticipated results from cost and efficiency initiatives; risks inherent in marketing operations; risks associated with technology; the
Companys ability to acquire or find additional reserves; imprecision of reserves estimates and estimates of recoverable quantities of natural gas and liquids from resource plays and other sources not currently classified as proved, probable or
possible reserves or economic contingent resources, including future net revenue estimates; risks associated with past and future divestitures of certain assets or other transactions or receive amounts contemplated under the transaction agreements
(such transactions may include third-party capital investments, farm-outs or partnerships, which Encana may refer to from time to time as partnerships or joint ventures and the funds received in respect thereof which Encana
may refer to from time to time as proceeds, deferred purchase price and/or carry capital, regardless of the legal form) as a result of various conditions not being met; and other risks and uncertainties impacting
Encanas business, as described from time to time in its most recent MD&A, financial statements, Annual Information Form and Form 40-F, as filed on SEDAR and EDGAR.
Although Encana believes the expectations represented by such FLS are reasonable, there can be no assurance that such expectations will prove to be
correct. Readers are cautioned that the assumptions, risks and uncertainties referenced above are not exhaustive. FLS in this document are made as of the date of this document and, except as required by law, Encana undertakes no obligation to update
publicly or revise any FLS. The FLS contained in this document are expressly qualified by these cautionary statements.
Further information on
Encana Corporation is available on the companys website, www.encana.com, or by contacting:
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Investor contacts: |
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Media contacts: |
Brendan McCracken |
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Simon Scott |
Vice-President, Investor Relations |
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Vice-President, Communications |
(403) 645-2978 |
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(403) 645-2526 |
Brendan.McCracken@encana.com |
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Simon.Scott@encana.com |
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Brian Dutton |
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Jay Averill |
(403) 645-2285 |
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Director, Media Relations |
Brian.Dutton@encana.com |
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(403) 645-4747 |
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Jay.Averill@encana.com |
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Patti Posadowski |
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Doug McIntyre |
(403) 645-2252 |
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Sr. Advisor, Media Relations |
Patti.Posadowski@encana.com |
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(403) 645-6553 |
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Doug.McIntyre@encana.com |
SOURCE: Encana Corporation
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Encana Corporation |
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Encana Corporation |
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Managements Discussion and Analysis |
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For the period ended September 30, 2015 |
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(Prepared in U.S. Dollars)
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Managements Discussion and Analysis
This Managements Discussion and Analysis (MD&A) for Encana Corporation (Encana or the Company) should be
read with the unaudited interim Condensed Consolidated Financial Statements for the period ended September 30, 2015 (Interim Condensed Consolidated Financial Statements), as well as the audited Consolidated Financial Statements and
MD&A for the year ended December 31, 2014.
The Interim Condensed Consolidated Financial Statements and comparative information have
been prepared in accordance with United States (U.S.) generally accepted accounting principles (U.S. GAAP) and in U.S. dollars, except where another currency has been indicated. References to C$ are to Canadian dollars.
Encanas financial results are consolidated in Canadian dollars; however, the Company has adopted the U.S. dollar as its reporting currency to facilitate a more direct comparison to other North American oil and gas companies. Production volumes
are presented on an after royalties basis consistent with U.S. oil and gas reporting standards and the disclosure of U.S. oil and gas companies. The term liquids is used to represent oil, natural gas liquids (NGLs or
NGL) and condensate. The term liquids rich is used to represent natural gas streams with associated liquids volumes. This document is dated November 11, 2015.
For convenience, references in this document to Encana, the Company, we, us, our and
its may, where applicable, refer only to or include any relevant direct and indirect subsidiary corporations and partnerships (Subsidiaries) of Encana Corporation, and the assets, activities and initiatives of such
Subsidiaries.
Certain measures in this document do not have any standardized meaning as prescribed by U.S. GAAP and, therefore, are
considered non-GAAP measures. Non-GAAP measures are commonly used in the oil and gas industry and by Encana to provide shareholders and potential investors with additional information regarding the Companys liquidity and its ability to
generate funds to finance its operations. Non-GAAP measures include: Cash Flow; Free Cash Flow; Operating Earnings (Loss); Upstream Operating Cash Flow, excluding Hedging; Operating Netback; Debt to Debt Adjusted Cash Flow; and Debt to Adjusted
Capitalization. Further information regarding these measures can be found in the Non-GAAP Measures section of this MD&A, including reconciliations of Cash from Operating Activities to Cash Flow and Free Cash Flow, and of Net Earnings (Loss)
Attributable to Common Shareholders to Operating Earnings (Loss).
The following volumetric measures may be abbreviated throughout this
MD&A: thousand cubic feet (Mcf); million cubic feet (MMcf) per day (MMcf/d); billion cubic feet per day (Bcf/d); barrel (bbl); thousand barrels (Mbbls) per day
(Mbbls/d); barrels of oil equivalent (BOE) per day (BOE/d); thousand barrels of oil equivalent (MBOE) per day (MBOE/d); million British thermal units (MMBtu); gigajoule
(GJ).
Readers should also read the Advisory section located at the end of this document, which provides information on
Forward-Looking Statements and Oil and Gas Information.
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MD&A
Prepared using U.S. GAAP in US$ |
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Encanas Strategic Objectives |
Encana is a leading North American energy producer that is focused on developing its strong portfolio of resource plays
producing natural gas, oil and NGLs. 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 balancing its commodity portfolio,
focusing capital investments in strategic high return scalable projects, maintaining portfolio flexibility to respond to changing market conditions, maximizing profitability through operating efficiencies, reducing costs and preserving balance sheet
strength.
Encana continually strives to improve operating efficiencies, foster technological innovation and lower its cost structures, while
reducing its environmental footprint through play optimization. The Companys resource play hub model utilizes highly integrated production facilities to develop resources by drilling multiple wells from central pad sites. Capital and operating
efficiencies are achieved through repeatable operations, optimizing equipment and processes and by applying continuous improvement techniques.
Encana hedges a portion of its expected natural gas and oil production volumes. The Companys hedging program reduces volatility and helps sustain
Cash Flow and Operating Netbacks during periods of lower prices. Further information on the Companys commodity price positions as at September 30, 2015 can be found in the Results Overview section of this MD&A and in Note 21 to the
Interim Condensed Consolidated Financial Statements.
Additional information on expected results can be found in Encanas 2015 Corporate
Guidance on the Companys website www.encana.com.
Encanas reportable segments are determined based on the Companys operations and geographic locations as
follows:
|
● |
|
Canadian Operations includes the exploration for, development of, and production of natural gas, oil and NGLs and other related activities within
Canada. |
|
● |
|
USA Operations includes the exploration for, development of, and production of natural gas, oil and NGLs and other related activities within the U.S.
|
|
● |
|
Market Optimization is primarily responsible for the sale of the Companys 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 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 Companys upstream production to third party customers. Transactions between segments are based on market values and are eliminated on
consolidation. Financial information is presented on an after eliminations basis within this MD&A. |
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.
|
|
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
Highlights
In the three months ended September 30, 2015, Encana reported:
|
● |
|
Cash Flow of $371 million and an Operating Loss of $24 million. |
|
● |
|
Net Loss of $1,236 million, including an after-tax non-cash ceiling test impairment of $1,066 million. |
|
● |
|
Average realized natural gas prices, including financial hedges, of $3.71 per Mcf. Average realized oil prices, including financial hedges, of $49.38 per
bbl. Average realized NGL prices of $19.57 per bbl. |
|
● |
|
Average natural gas production volumes of 1,547 MMcf/d and average oil and NGL production volumes of 140.4 Mbbls/d. |
|
● |
|
Dividends paid of $0.07 per share. |
In the nine months
ended September 30, 2015, Encana reported:
|
● |
|
Cash Flow of $1,047 million and an Operating Loss of $172 million. |
|
● |
|
Net Loss of $4,553 million, including after-tax non-cash ceiling test impairments of $3,616 million. |
|
● |
|
Average realized natural gas prices, including financial hedges, of $4.04 per Mcf. Average realized oil prices, including financial hedges, of $49.64 per
bbl. Average realized NGL prices of $21.78 per bbl. |
|
● |
|
Average natural gas production volumes of 1,656 MMcf/d and average oil and NGL production volumes of 129.5 Mbbls/d. |
|
● |
|
Dividends paid of $0.21 per share. |
|
● |
|
Cash and cash equivalents of $352 million at period end. |
Significant developments for the Company during the nine months ended September 30, 2015 included the following:
|
● |
|
Announced an agreement with GEP Haynesville, LLC (GeoSouthern) on August 25, 2015, to sell the Companys Haynesville natural gas
assets, which include approximately 112,000 net acres of leasehold, plus additional fee mineral lands located in northern Louisiana, for cash consideration of approximately $850 million. Based on the January 1, 2015 effective date of the
transaction, Encana will also reduce its gathering and midstream commitments by approximately $480 million (undiscounted) through the transfer of current and future obligations and will transport and market GeoSoutherns Haynesville production
on a fee for service basis for the next five years. The transaction is expected to close in the fourth quarter of 2015, with an effective date of January 1, 2015, and is subject to satisfaction of normal closing conditions and regulatory
approvals. The Company expects to use the proceeds received to reduce debt. |
|
● |
|
Completed a bought deal offering of 85,616,500 common shares of Encana and the over-allotment option of an additional 12,842,475 common shares of Encana at a
price of C$14.60 per common share (the Share Offering). The Share Offering was completed during March 2015 for aggregate gross proceeds of approximately C$1.44 billion. |
|
● |
|
Redeemed the Companys $700 million 5.90 percent notes due December 1, 2017 and its C$750 million 5.80 percent medium-term notes due
January 18, 2018, in April 2015, using net proceeds from the Share Offering and cash on hand. |
|
● |
|
Closed the sale of the Companys working interest in certain properties in central and southern Alberta to Ember Resources Inc. on January 15, 2015
for proceeds of approximately C$558 million, after closing adjustments. |
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
|
|
|
● |
|
Closed the sale of certain natural gas gathering and compression assets in northeastern British Columbia to Veresen Midstream Limited Partnership
(VMLP) on March 31, 2015 for cash consideration net to Encana of approximately C$453 million, after closing adjustments. |
Subsequent Event
On October 8, 2015, Encana announced an agreement to sell its DJ Basin assets in Colorado, comprising 51,000 net acres, to a new entity jointly
owned by the Canada Pension Plan Investment Board and The Broe Group for total consideration of approximately $900 million. The transaction is expected to close in the fourth quarter of 2015, with an effective date of April 1, 2015, and is
subject to satisfaction of normal closing conditions, regulatory approvals and other adjustments.
|
|
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
Financial Results
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine months
ended September 30 |
|
|
|
|
2015 |
|
|
|
|
2014 |
|
|
|
|
2013 |
|
($ millions, except as indicated) |
|
2015 |
|
|
2014 |
|
|
|
|
Q3 |
|
|
Q2 |
|
|
Q1 |
|
|
|
|
Q4 |
|
|
Q3 |
|
|
Q2 |
|
|
Q1 |
|
|
|
|
Q4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flow (1) |
|
$ |
1,047 |
|
|
$ |
2,557 |
|
|
|
|
$ |
371 |
|
|
$ |
181 |
|
|
$ |
495 |
|
|
|
|
$ |
377 |
|
|
$ |
807 |
|
|
$ |
656 |
|
|
$ |
1,094 |
|
|
|
|
$ |
677 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ per share - diluted |
|
|
1.29 |
|
|
|
3.45 |
|
|
|
|
|
0.44 |
|
|
|
0.22 |
|
|
|
0.65 |
|
|
|
|
|
0.51 |
|
|
|
1.09 |
|
|
|
0.89 |
|
|
|
1.48 |
|
|
|
|
|
0.91 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Earnings (Loss) (1), (2) |
|
|
(172 |
) |
|
|
967 |
|
|
|
|
|
(24 |
) |
|
|
(167 |
) |
|
|
19 |
|
|
|
|
|
35 |
|
|
|
281 |
|
|
|
171 |
|
|
|
515 |
|
|
|
|
|
226 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ per share - diluted |
|
|
(0.21 |
) |
|
|
1.30 |
|
|
|
|
|
(0.03 |
) |
|
|
(0.20 |
) |
|
|
0.03 |
|
|
|
|
|
0.05 |
|
|
|
0.38 |
|
|
|
0.23 |
|
|
|
0.70 |
|
|
|
|
|
0.31 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Earnings (Loss) Attributable to Common Shareholders |
|
|
(4,553 |
) |
|
|
3,194 |
|
|
|
|
|
(1,236 |
) |
|
|
(1,610 |
) |
|
|
(1,707 |
) |
|
|
|
|
198 |
|
|
|
2,807 |
|
|
|
271 |
|
|
|
116 |
|
|
|
|
|
(251 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ per share - basic & diluted
|
|
|
(5.59 |
) |
|
|
4.31 |
|
|
|
|
|
(1.47 |
) |
|
|
(1.91 |
) |
|
|
(2.25 |
) |
|
|
|
|
0.27 |
|
|
|
3.79 |
|
|
|
0.37 |
|
|
|
0.16 |
|
|
|
|
|
(0.34 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues, Net of Royalties |
|
|
3,391 |
|
|
|
5,765 |
|
|
|
|
|
1,312 |
|
|
|
830 |
|
|
|
1,249 |
|
|
|
|
|
2,254 |
|
|
|
2,285 |
|
|
|
1,588 |
|
|
|
1,892 |
|
|
|
|
|
1,423 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized Hedging Gain (Loss), before tax |
|
|
614 |
|
|
|
(215 |
) |
|
|
|
|
213 |
|
|
|
161 |
|
|
|
240 |
|
|
|
|
|
124 |
|
|
|
28 |
|
|
|
(102 |
) |
|
|
(141 |
) |
|
|
|
|
174 |
|
Unrealized Hedging Gain (Loss), before tax |
|
|
(241 |
) |
|
|
(45 |
) |
|
|
|
|
173 |
|
|
|
(278 |
) |
|
|
(136 |
) |
|
|
|
|
489 |
|
|
|
231 |
|
|
|
9 |
|
|
|
(285 |
) |
|
|
|
|
(301 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Upstream Operating Cash Flow |
|
|
1,712 |
|
|
|
3,097 |
|
|
|
|
|
531 |
|
|
|
479 |
|
|
|
702 |
|
|
|
|
|
821 |
|
|
|
982 |
|
|
|
800 |
|
|
|
1,315 |
|
|
|
|
|
901 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Upstream Operating Cash Flow, excluding Hedging (1) |
|
|
1,083 |
|
|
|
3,305 |
|
|
|
|
|
314 |
|
|
|
315 |
|
|
|
454 |
|
|
|
|
|
694 |
|
|
|
952 |
|
|
|
898 |
|
|
|
1,455 |
|
|
|
|
|
728 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital Investment |
|
|
1,952 |
|
|
|
1,669 |
|
|
|
|
|
473 |
|
|
|
743 |
|
|
|
736 |
|
|
|
|
|
857 |
|
|
|
598 |
|
|
|
560 |
|
|
|
511 |
|
|
|
|
|
717 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Acquisitions & (Divestitures) (3) |
|
|
(1,077 |
) |
|
|
(1,379 |
) |
|
|
|
|
(99 |
) |
|
|
(140 |
) |
|
|
(838 |
) |
|
|
|
|
50 |
|
|
|
(2,007 |
) |
|
|
652 |
|
|
|
(24 |
) |
|
|
|
|
(72 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Free Cash Flow (1) |
|
|
(905 |
) |
|
|
888 |
|
|
|
|
|
(102 |
) |
|
|
(562 |
) |
|
|
(241 |
) |
|
|
|
|
(480 |
) |
|
|
209 |
|
|
|
96 |
|
|
|
583 |
|
|
|
|
|
(40 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ceiling Test Impairments, after tax |
|
|
(3,616 |
) |
|
|
- |
|
|
|
|
|
(1,066 |
) |
|
|
(1,328 |
) |
|
|
(1,222 |
) |
|
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain (Loss) on Divestitures, after tax
|
|
|
9 |
|
|
|
2,534 |
|
|
|
|
|
(2 |
) |
|
|
1 |
|
|
|
10 |
|
|
|
|
|
(11 |
) |
|
|
2,399 |
|
|
|
135 |
|
|
|
- |
|
|
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production Volumes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas (MMcf/d) |
|
|
1,656 |
|
|
|
2,515 |
|
|
|
|
|
1,547 |
|
|
|
1,568 |
|
|
|
1,857 |
|
|
|
|
|
1,861 |
|
|
|
2,199 |
|
|
|
2,541 |
|
|
|
2,809 |
|
|
|
|
|
2,744 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil & NGLs (Mbbls/d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
|
85.8 |
|
|
|
42.9 |
|
|
|
|
|
91.9 |
|
|
|
86.2 |
|
|
|
79.2 |
|
|
|
|
|
68.8 |
|
|
|
62.1 |
|
|
|
34.2 |
|
|
|
32.1 |
|
|
|
|
|
33.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGLs |
|
|
43.7 |
|
|
|
37.3 |
|
|
|
|
|
48.5 |
|
|
|
41.1 |
|
|
|
41.5 |
|
|
|
|
|
37.6 |
|
|
|
41.9 |
|
|
|
34.0 |
|
|
|
35.8 |
|
|
|
|
|
33.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Oil & NGLs |
|
|
129.5 |
|
|
|
80.2 |
|
|
|
|
|
140.4 |
|
|
|
127.3 |
|
|
|
120.7 |
|
|
|
|
|
106.4 |
|
|
|
104.0 |
|
|
|
68.2 |
|
|
|
67.9 |
|
|
|
|
|
66.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Production (MBOE/d) |
|
|
405.6 |
|
|
|
499.3 |
|
|
|
|
|
398.3 |
|
|
|
388.7 |
|
|
|
430.1 |
|
|
|
|
|
416.7 |
|
|
|
470.6 |
|
|
|
491.8 |
|
|
|
536.1 |
|
|
|
|
|
523.4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production Mix (%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas |
|
|
68 |
|
|
|
84 |
|
|
|
|
|
65 |
|
|
|
67 |
|
|
|
72 |
|
|
|
|
|
74 |
|
|
|
78 |
|
|
|
86 |
|
|
|
87 |
|
|
|
|
|
87 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil & NGLs |
|
|
32 |
|
|
|
16 |
|
|
|
|
|
35 |
|
|
|
33 |
|
|
|
28 |
|
|
|
|
|
26 |
|
|
|
22 |
|
|
|
14 |
|
|
|
13 |
|
|
|
|
|
13 |
|
|
(1) |
A non-GAAP measure, which is defined in the Non-GAAP Measures section of this MD&A. |
|
(2) |
In continued support of Encanas strategy, organizational structure changes were formalized in Q2 2015 and resulted in a revision to the Q1 2015
Operating Earnings to exclude restructuring charges incurred in the first quarter. |
|
(3) |
Excludes the impact of the PrairieSky Royalty Ltd. divestiture and the Athlon Energy Inc. acquisition during 2014, as summarized in the Net Capital Investment
section of this MD&A. |
Encanas quarterly net earnings can be significantly impacted by fluctuations in commodity prices,
realized and unrealized hedging gains and losses, production volumes, foreign exchange rates, ceiling test impairments and gains or losses on divestitures, which are provided in the Financial Results table and Prices and Foreign Exchange Rates table
within this MD&A. Quarterly net earnings are also impacted by Encanas interim income tax
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
|
|
expense calculated using the estimated annual effective income tax rate as discussed in the Other Operating Results section of this MD&A, and by acquisition and divestiture transactions as
discussed in the Net Capital Investment section of this MD&A.
Under full cost accounting, the carrying amount of Encanas natural gas and
oil properties within each country cost centre is subject to a ceiling test performed quarterly. Ceiling test impairments are recognized when the capitalized costs, net of accumulated depletion and the related deferred income taxes, exceed the sum
of the estimated after-tax future net cash flows from proved reserves as calculated under Securities and Exchange Commission (SEC) requirements using the 12-month average trailing prices and discounted at 10 percent.
In the third quarter and first nine months of 2015, the Company recognized after-tax non-cash ceiling test impairments of $1,066 million and $3,616
million, respectively, in the U.S. cost centre. The non-cash ceiling test impairments primarily resulted from the decline in the 12-month average trailing commodity prices. Further declines in the 12-month average trailing commodity prices could
reduce proved reserves volumes and values and result in the recognition of future ceiling test impairments. Future ceiling test impairments can also result from changes to reserves estimates, future development costs, capitalized costs and unproved
property costs. Proceeds received from natural gas and oil property divestitures are generally deducted from the Companys capitalized costs and can reduce the likelihood of ceiling test impairments.
The Company believes that the discounted after-tax future net cash flows from proved reserves required to be used in the ceiling test calculation are
not indicative of the fair market value of Encanas natural gas and oil properties or the future net cash flows expected to be generated from such properties. The discounted after-tax future net cash flows do not consider the fair market value
of unamortized unproved properties, or probable or possible natural gas and liquids reserves. In addition, there is no consideration given to the effect of future changes in commodity prices. Encana manages its business using estimates of reserves
and resources based on forecast prices and costs.
Three months ended September 30, 2015 versus September 30, 2014
Cash Flow of $371 million decreased $436 million in the three months ended September 30, 2015 and was impacted by the following significant items:
|
● |
|
Average realized natural gas prices, excluding financial hedges, were $2.60 per Mcf compared to $3.88 per Mcf in 2014 reflecting lower benchmark prices.
Lower realized natural gas prices decreased revenues $180 million. Average realized liquids prices, excluding financial hedges, were $34.52 per bbl compared to $73.48 per bbl in 2014 reflecting lower benchmark prices. Lower realized liquids prices
decreased revenues $396 million. |
|
● |
|
Average natural gas production volumes of 1,547 MMcf/d decreased 652 MMcf/d from 2,199 MMcf/d in 2014 primarily due to divestitures, natural declines in
Haynesville and Piceance and lower production from Deep Panuke, partially offset by successful drilling programs in Montney and Duvernay. Lower natural gas volumes decreased revenues $238 million. Average oil and NGL production volumes of 140.4
Mbbls/d increased 36.4 Mbbls/d from 104.0 Mbbls/d in 2014 primarily due to acquisitions and successful drilling programs in liquids rich plays, partially offset by divestitures. Higher oil and NGL volumes increased revenues $139 million.
|
|
● |
|
Realized financial hedging gains before tax were $213 million compared to $28 million in 2014. |
|
● |
|
Transportation and processing expense decreased $51 million primarily due to the lower U.S./Canadian dollar exchange rate, divestitures and lower production
from Deep Panuke, partially offset by higher volumes in Montney. |
|
● |
|
Current tax was a recovery of $19 million compared to an expense of $244 million in 2014 as discussed in the Other Operating Results section of this
MD&A. Cash Flow excludes cash tax on the sale of assets as discussed in the Non-GAAP measures section of this MD&A. |
|
|
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
Operating Loss in the third quarter of 2015 was $24 million compared to Operating Earnings of $281 million
in 2014 primarily due to the items discussed in the Cash Flow section. Operating Loss in the third quarter of 2015 was also impacted by higher foreign exchange losses on settlements and the revaluation of other monetary assets and liabilities, lower
depreciation, depletion and amortization (DD&A) and changes in deferred tax.
Net Loss Attributable to Common Shareholders in the
third quarter of 2015 was $1,236 million compared to Net Earnings Attributable to Common Shareholders of $2,807 million in 2014 primarily due to a lower after-tax gain on divestitures, an after-tax non-cash ceiling test impairment and the items
discussed in the Cash Flow and Operating Earnings sections. Net Loss in the third quarter of 2015 was also impacted by lower after-tax unrealized hedging gains and changes in deferred tax.
Nine months ended September 30, 2015 versus September 30, 2014
Cash Flow of $1,047 million decreased $1,510 million in the nine months ended September 30, 2015 and was impacted by the following significant
items:
|
● |
|
Average realized natural gas prices, excluding financial hedges, were $2.87 per Mcf compared to $4.99 per Mcf in 2014 reflecting lower benchmark prices.
Lower realized natural gas prices decreased revenues $911 million. Average realized liquids prices, excluding financial hedges, were $37.45 per bbl compared to $71.66 per bbl in 2014 reflecting lower benchmark prices. Lower realized liquids prices
decreased revenues $812 million. |
|
● |
|
Average natural gas production volumes of 1,656 MMcf/d decreased 859 MMcf/d from 2,515 MMcf/d in 2014 primarily due to divestitures, natural declines in
Haynesville and Piceance and lower production from Deep Panuke, partially offset by successful drilling programs in Montney and Duvernay. Lower natural gas volumes decreased revenues $1,222 million. Average oil and NGL production volumes of 129.5
Mbbls/d increased 49.3 Mbbls/d from 80.2 Mbbls/d in 2014 primarily due to acquisitions and successful drilling programs in liquids rich plays, partially offset by divestitures. Higher oil and NGL volumes increased revenues $566 million.
|
|
● |
|
Realized financial hedging gains before tax were $614 million compared to losses of $215 million in 2014. |
|
● |
|
Transportation and processing expense decreased $190 million primarily due to divestitures, the lower U.S./Canadian dollar exchange rate and lower production
from Deep Panuke, partially offset by higher volumes in Montney. |
|
● |
|
Interest expense increased $106 million primarily due to a one-time interest payment of approximately $165 million resulting from the April 2015 early debt
redemptions, partially offset by lower interest on debt following these redemptions. |
|
● |
|
Current tax was a recovery of $38 million compared to an expense of $241 million in 2014 as discussed in the Other Operating Results section of this
MD&A. Cash Flow excludes cash tax on the sale of assets as discussed in the Non-GAAP measures section of this MD&A. |
Operating Loss in the first nine months of 2015 was $172 million compared to Operating Earnings of $967 million in 2014 primarily due to the items
discussed in the Cash Flow section. Operating Loss in the first nine months of 2015 was also impacted by higher foreign exchange losses on settlements and the revaluation of other monetary assets and liabilities, lower long-term compensation costs
due to the decrease in the Encana share price, lower DD&A and changes in deferred tax.
Net Loss Attributable to Common Shareholders in the
first nine months of 2015 was $4,553 million compared to Net Earnings Attributable to Common Shareholders of $3,194 million in 2014 primarily due to after-tax non-cash ceiling test impairments, a lower after-tax gain on divestitures and the items
discussed in the Cash Flow and Operating Earnings sections. Net Loss in the first nine months of 2015 was also impacted by a higher after-tax non-operating foreign exchange loss, higher after-tax unrealized hedging losses and changes in deferred
tax.
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
|
|
Prices and Foreign Exchange Rates
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine months ended September 30 |
|
|
|
|
2015 |
|
|
|
|
2014 |
|
|
|
|
2013 |
|
(average for the period) |
|
2015 |
|
|
2014 |
|
|
|
|
Q3 |
|
|
Q2 |
|
|
Q1 |
|
|
|
|
Q4 |
|
|
Q3 |
|
|
Q2 |
|
|
Q1 |
|
|
|
|
Q4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Encana Realized Pricing |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Including Hedging |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas ($/Mcf) |
|
|
$ 4.04 |
|
|
|
$ 4.70 |
|
|
|
|
|
$ 3.71 |
|
|
|
$ 3.52 |
|
|
|
$ 4.78 |
|
|
|
|
|
$ 4.16 |
|
|
|
$ 4.03 |
|
|
|
$ 4.08 |
|
|
|
$ 5.82 |
|
|
|
|
|
$ 4.34 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil & NGLs ($/bbl) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
|
49.64 |
|
|
|
89.09 |
|
|
|
|
|
49.38 |
|
|
|
53.08 |
|
|
|
46.17 |
|
|
|
|
|
80.38 |
|
|
|
90.22 |
|
|
|
89.55 |
|
|
|
86.34 |
|
|
|
|
|
85.39 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGLs |
|
|
21.78 |
|
|
|
50.55 |
|
|
|
|
|
19.57 |
|
|
|
24.28 |
|
|
|
21.92 |
|
|
|
|
|
40.87 |
|
|
|
48.76 |
|
|
|
49.39 |
|
|
|
53.79 |
|
|
|
|
|
48.59 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Oil & NGLs |
|
|
40.24 |
|
|
|
71.18 |
|
|
|
|
|
39.09 |
|
|
|
43.78 |
|
|
|
37.83 |
|
|
|
|
|
66.40 |
|
|
|
73.50 |
|
|
|
69.53 |
|
|
|
69.19 |
|
|
|
|
|
67.01 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total ($/BOE) |
|
|
29.36 |
|
|
|
35.12 |
|
|
|
|
|
28.17 |
|
|
|
28.53 |
|
|
|
31.24 |
|
|
|
|
|
35.55 |
|
|
|
35.06 |
|
|
|
30.75 |
|
|
|
39.22 |
|
|
|
|
|
31.23 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Excluding Hedging |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas ($/Mcf) |
|
|
2.87 |
|
|
|
4.99 |
|
|
|
|
|
2.60 |
|
|
|
2.37 |
|
|
|
3.53 |
|
|
|
|
|
3.94 |
|
|
|
3.88 |
|
|
|
4.46 |
|
|
|
6.37 |
|
|
|
|
|
3.69 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil & NGLs ($/bbl) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
|
45.43 |
|
|
|
89.99 |
|
|
|
|
|
42.40 |
|
|
|
53.15 |
|
|
|
40.53 |
|
|
|
|
|
66.38 |
|
|
|
90.18 |
|
|
|
92.93 |
|
|
|
86.43 |
|
|
|
|
|
82.54 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGLs |
|
|
21.78 |
|
|
|
50.55 |
|
|
|
|
|
19.57 |
|
|
|
24.28 |
|
|
|
21.92 |
|
|
|
|
|
40.87 |
|
|
|
48.76 |
|
|
|
49.39 |
|
|
|
53.79 |
|
|
|
|
|
48.59 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Oil & NGLs |
|
|
37.45 |
|
|
|
71.66 |
|
|
|
|
|
34.52 |
|
|
|
43.83 |
|
|
|
34.13 |
|
|
|
|
|
57.35 |
|
|
|
73.48 |
|
|
|
71.23 |
|
|
|
69.23 |
|
|
|
|
|
65.58 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total ($/BOE) |
|
|
23.68 |
|
|
|
36.64 |
|
|
|
|
|
22.26 |
|
|
|
23.90 |
|
|
|
24.82 |
|
|
|
|
|
32.25 |
|
|
|
34.36 |
|
|
|
32.93 |
|
|
|
42.12 |
|
|
|
|
|
27.63 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Price Benchmarks |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NYMEX ($/MMBtu) |
|
|
2.80 |
|
|
|
4.55 |
|
|
|
|
|
2.77 |
|
|
|
2.64 |
|
|
|
2.98 |
|
|
|
|
|
4.00 |
|
|
|
4.06 |
|
|
|
4.67 |
|
|
|
4.94 |
|
|
|
|
|
3.60 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
AECO (C$/Mcf) |
|
|
2.81 |
|
|
|
4.55 |
|
|
|
|
|
2.80 |
|
|
|
2.67 |
|
|
|
2.95 |
|
|
|
|
|
4.01 |
|
|
|
4.22 |
|
|
|
4.68 |
|
|
|
4.76 |
|
|
|
|
|
3.15 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Algonquin City Gate ($/MMBtu) |
|
|
5.31 |
|
|
|
9.09 |
|
|
|
|
|
2.37 |
|
|
|
2.24 |
|
|
|
11.41 |
|
|
|
|
|
4.99 |
|
|
|
2.97 |
|
|
|
4.23 |
|
|
|
20.28 |
|
|
|
|
|
7.80 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basis Differential ($/MMBtu) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
AECO/NYMEX |
|
|
0.56 |
|
|
|
0.38 |
|
|
|
|
|
0.61 |
|
|
|
0.50 |
|
|
|
0.57 |
|
|
|
|
|
0.44 |
|
|
|
0.16 |
|
|
|
0.40 |
|
|
|
0.60 |
|
|
|
|
|
0.59 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil Price Benchmarks |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
West Texas Intermediate (WTI) ($/bbl) |
|
|
51.00 |
|
|
|
99.61 |
|
|
|
|
|
46.43 |
|
|
|
57.94 |
|
|
|
48.64 |
|
|
|
|
|
73.15 |
|
|
|
97.17 |
|
|
|
102.99 |
|
|
|
98.68 |
|
|
|
|
|
97.46 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Edmonton Light Sweet (C$/bbl) |
|
|
58.63 |
|
|
|
100.87 |
|
|
|
|
|
56.23 |
|
|
|
67.71 |
|
|
|
51.94 |
|
|
|
|
|
75.69 |
|
|
|
97.16 |
|
|
|
105.61 |
|
|
|
99.83 |
|
|
|
|
|
86.58 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign Exchange |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average U.S./Canadian Dollar Exchange Rate |
|
|
0.794 |
|
|
|
0.914 |
|
|
|
|
|
0.764 |
|
|
|
0.813 |
|
|
|
0.806 |
|
|
|
|
|
0.881 |
|
|
|
0.918 |
|
|
|
0.917 |
|
|
|
0.906 |
|
|
|
|
|
0.953 |
|
Encanas financial results are influenced by fluctuations in commodity prices, price differentials and the
U.S./Canadian dollar exchange rate. In the third quarter and first nine months of 2015, Encanas average realized natural gas price, excluding hedging, reflected lower benchmark prices compared to 2014. Hedging activities contributed $1.11 per
Mcf to Encanas average realized natural gas price in the third quarter of 2015 and $1.17 per Mcf in the first nine months of 2015. The average realized natural gas price for production from Deep Panuke was $9.40 per Mcf in the first nine
months of 2015 compared to $8.71 per Mcf in 2014 and increased Encanas average realized natural gas price $0.29 per Mcf in the first nine months of 2015 compared to $0.37 per Mcf in 2014.
In the third quarter and first nine months of 2015, Encanas average realized oil and NGL prices, excluding hedging, reflected lower benchmark
prices compared to 2014. Hedging activities contributed $6.98 per bbl to Encanas average realized oil price in the third quarter of 2015 and $4.21 per bbl in the first nine months of 2015.
|
|
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
Financial Hedge Agreements
As a means of managing commodity price volatility and its impact on cash flows, Encana enters into various financial hedge agreements. Unsettled
derivative financial contracts are recorded at the date of the financial statements based on the fair value of the contracts. Changes in fair value result from volatility in forward commodity prices and changes in the balance of unsettled contracts
between periods. The changes in fair value are recognized in revenue as unrealized hedging gains and losses. Realized hedging gains and losses are recognized in revenue when derivative financial contracts are settled.
During the third quarter of 2015, Encana entered into NYMEX and WTI three-way costless collars. The three-way costless collars are a combination of a
sold call, purchased put and a sold 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 partial downside price protection through the combination
of the put options.
The tables below summarize Encanas hedging contracts on expected future production as at September 30, 2015.
Natural Gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Term |
|
|
Notional
Volumes (MMcf/d) |
|
|
Average
Price ($/Mcf) |
|
|
|
|
|
NYMEX Fixed Price Contracts |
|
|
2015 |
|
|
|
1,000 |
|
|
|
4.29 |
|
|
|
|
|
NYMEX Fixed Price Contracts |
|
|
2016 |
|
|
|
95 |
|
|
|
2.98 |
|
|
|
|
|
NYMEX Three-Way Costless Collars |
|
|
2016 |
|
|
|
300 |
|
|
|
|
|
|
|
|
|
Sold call price |
|
|
|
|
|
|
|
|
|
|
3.43 |
|
|
|
|
|
Bought put price |
|
|
|
|
|
|
|
|
|
|
3.21 |
|
|
|
|
|
Sold put price |
|
|
|
|
|
|
|
|
|
|
2.72 |
|
Crude Oil
|
|
|
|
Term |
|
|
Notional
Volumes (Mbbls/d) |
|
|
Average
Price ($/bbl) |
|
|
|
|
|
WTI Fixed Price Contracts |
|
|
2015 |
|
|
|
88.9 |
|
|
|
58.09 |
|
|
|
|
|
WTI Fixed Price Contracts |
|
|
2016 |
|
|
|
38.0 |
|
|
|
62.83 |
|
|
|
|
|
WTI Fixed Price Swaptions (1) |
|
|
2016 |
|
|
|
7.5 |
|
|
|
50.34 |
|
|
|
|
|
WTI Three-Way Costless Collars |
|
|
2016 |
|
|
|
18.3 |
|
|
|
|
|
|
|
|
|
Sold call price |
|
|
|
|
|
|
|
|
|
|
63.03 |
|
|
|
|
|
Bought put price |
|
|
|
|
|
|
|
|
|
|
55.00 |
|
|
|
|
|
Sold put price |
|
|
|
|
|
|
|
|
|
|
47.24 |
|
|
(1) |
The WTI Fixed Price Swaptions give the counterparty the option to extend fourth quarter 2015 fixed price swaps to March 2016 at the same price.
|
The Companys hedging program helps sustain Cash Flow and Operating Netbacks during periods of lower prices. For additional
information, see the Risk Management Financial Risks section of this MD&A.
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
|
|
Foreign Exchange
As disclosed in the Prices and Foreign Exchange Rates table, the average U.S./Canadian dollar exchange rate decreased 0.154 in the third quarter of 2015
compared to the third quarter of 2014 and 0.120 in the first nine months of 2015 compared to the first nine months of 2014. The table below summarizes selected foreign exchange impacts on Encanas financial results when compared to the same
periods in 2014.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30 |
|
|
|
|
Nine months ended
September 30 |
|
|
|
$ millions |
|
|
$/BOE |
|
|
|
|
$ millions |
|
|
$/BOE |
|
|
|
|
|
|
|
Increase (Decrease) in: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital Investment |
|
$ |
(49 |
) |
|
|
|
|
|
|
|
$ |
(121 |
) |
|
|
|
|
|
|
|
|
|
|
Transportation and Processing Expense |
|
|
(34 |
) |
|
$ |
(0.93 |
) |
|
|
|
|
(83 |
) |
|
|
$ (0.75) |
|
|
|
|
|
|
|
Operating Expense |
|
|
(12 |
) |
|
|
(0.34 |
) |
|
|
|
|
(31 |
) |
|
|
(0.28) |
|
|
|
|
|
|
|
Administrative Expense |
|
|
(7 |
) |
|
|
(0.19 |
) |
|
|
|
|
(23 |
) |
|
|
(0.20) |
|
|
|
|
|
|
|
Depreciation, Depletion and Amortization |
|
|
(27 |
) |
|
|
(0.76 |
) |
|
|
|
|
(65 |
) |
|
|
(0.59) |
|
Price Sensitivities
Natural gas and liquids prices fluctuate in response to changing market forces, creating varying impacts on Encanas financial results. The
Companys potential exposure to commodity price fluctuations is summarized in the table below, which shows the estimated effects that certain price changes would have had on the Companys Cash Flow and Operating Earnings (Loss) for the
third quarter of 2015. The price sensitivities below are based on business conditions, transactions and production volumes during the third quarter of 2015. Accordingly, these sensitivities may not be indicative of financial results for other
periods, under other economic circumstances or with additional fluctuations in commodity prices.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Impact On |
|
($ millions, except as indicated) |
|
Price Change (1) |
|
|
|
|
Cash Flow |
|
|
|
|
Operating Earnings (Loss) |
|
|
|
|
|
|
|
Increase or Decrease in: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NYMEX Natural Gas Price |
|
|
+/- $0.50/MMBtu |
|
|
|
|
|
$ 20 |
|
|
|
|
|
$ 14 |
|
|
|
|
|
|
|
WTI Oil Price |
|
|
+/- $10.00/bbl |
|
|
|
|
|
50 |
|
|
|
|
|
33 |
|
(1) |
Assumes only one variable changes while all other variables are held constant. |
|
|
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended
September 30 |
|
|
|
|
Nine months ended
September 30 |
|
($ millions) |
|
2015 |
|
|
2014 |
|
|
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
|
Canadian Operations |
|
$ |
76 |
|
|
$ |
293 |
|
|
|
|
$ |
341 |
|
|
$ |
924 |
|
|
|
|
|
|
|
USA Operations |
|
|
394 |
|
|
|
305 |
|
|
|
|
|
1,605 |
|
|
|
737 |
|
|
|
|
|
|
|
Market Optimization |
|
|
1 |
|
|
|
(2 |
) |
|
|
|
|
1 |
|
|
|
- |
|
|
|
|
|
|
|
Corporate & Other |
|
|
2 |
|
|
|
2 |
|
|
|
|
|
5 |
|
|
|
8 |
|
Capital Investment |
|
|
473 |
|
|
|
598 |
|
|
|
|
|
1,952 |
|
|
|
1,669 |
|
Acquisitions |
|
|
- |
|
|
|
29 |
|
|
|
|
|
38 |
|
|
|
2,975 |
|
|
|
|
|
|
|
Divestitures |
|
|
(99 |
) |
|
|
(2,036 |
) |
|
|
|
|
(1,115 |
) |
|
|
(4,354 |
) |
Net Acquisitions & (Divestitures) |
|
|
(99 |
) |
|
|
(2,007 |
) |
|
|
|
|
(1,077 |
) |
|
|
(1,379 |
) |
Net Capital Investment |
|
$ |
374 |
|
|
$ |
(1,409 |
) |
|
|
|
$ |
875 |
|
|
$ |
290 |
|
Capital Investment by Play
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended
September 30 |
|
|
|
|
Nine months ended
September 30 |
|
($ millions) |
|
2015 |
|
|
2014 |
|
|
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
|
Canadian Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Montney (1) |
|
$ |
17 |
|
|
$ |
204 |
|
|
|
|
$ |
144 |
|
|
$ |
622 |
|
|
|
|
|
|
|
Duvernay |
|
|
58 |
|
|
|
58 |
|
|
|
|
|
185 |
|
|
|
210 |
|
|
|
|
|
|
|
Other Upstream Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wheatland (2) |
|
|
- |
|
|
|
10 |
|
|
|
|
|
4 |
|
|
|
40 |
|
|
|
|
|
|
|
Bighorn |
|
|
- |
|
|
|
3 |
|
|
|
|
|
- |
|
|
|
22 |
|
|
|
|
|
|
|
Deep Panuke |
|
|
- |
|
|
|
4 |
|
|
|
|
|
3 |
|
|
|
3 |
|
|
|
|
|
|
|
Other and emerging (1) |
|
|
1 |
|
|
|
14 |
|
|
|
|
|
5 |
|
|
|
27 |
|
Total Canadian Operations |
|
$ |
76 |
|
|
$ |
293 |
|
|
|
|
$ |
341 |
|
|
$ |
924 |
|
|
|
|
|
|
|
USA Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Eagle Ford |
|
$ |
142 |
|
|
$ |
113 |
|
|
|
|
$ |
514 |
|
|
$ |
125 |
|
|
|
|
|
|
|
Permian |
|
|
219 |
|
|
|
- |
|
|
|
|
|
761 |
|
|
|
- |
|
|
|
|
|
|
|
DJ Basin |
|
|
17 |
|
|
|
68 |
|
|
|
|
|
161 |
|
|
|
196 |
|
|
|
|
|
|
|
San Juan |
|
|
2 |
|
|
|
89 |
|
|
|
|
|
61 |
|
|
|
191 |
|
|
|
|
|
|
|
Other Upstream Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Piceance |
|
|
1 |
|
|
|
3 |
|
|
|
|
|
7 |
|
|
|
29 |
|
|
|
|
|
|
|
Haynesville |
|
|
15 |
|
|
|
1 |
|
|
|
|
|
27 |
|
|
|
34 |
|
|
|
|
|
|
|
Jonah |
|
|
- |
|
|
|
(2 |
) |
|
|
|
|
- |
|
|
|
25 |
|
|
|
|
|
|
|
East Texas |
|
|
- |
|
|
|
(1 |
) |
|
|
|
|
- |
|
|
|
9 |
|
|
|
|
|
|
|
Other and emerging |
|
|
(2 |
) |
|
|
34 |
|
|
|
|
|
74 |
|
|
|
128 |
|
Total USA Operations |
|
$ |
394 |
|
|
$ |
305 |
|
|
|
|
$ |
1,605 |
|
|
$ |
737 |
|
|
|
|
|
|
|
Capital Investment Strategic Assets
(1) |
|
$ |
436 |
|
|
$ |
375 |
|
|
|
|
$ |
1,604 |
|
|
$ |
957 |
|
|
(1) |
Montney has been realigned to include certain capital investments which were previously reported in Other and emerging. |
|
(2) |
Wheatland was previously presented as Clearwater. |
Strategic assets include Montney, Duvernay, Eagle Ford and Permian. Other Upstream Operations includes capital investment from plays that are not part
of the Companys current strategic focus as well as prospective plays that are under appraisal, including the Tuscaloosa Marine Shale (TMS), which is reported within Other and emerging in the USA Operations.
Capital investment associated with the Clearwater lands transferred to PrairieSky Royalty Ltd. (PrairieSky) was included in Encanas
Wheatland play until September 25, 2014, after which Encana no longer held an interest in PrairieSky.
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
|
|
Capital Investment
Capital investment during the first nine months of 2015 was $1,952 million (2014 $1,669 million) which reflected disciplined capital spending
focused on investment in the Companys strategic assets. During the first nine months of 2015, capital spending in Encanas strategic assets totaled $1,604 million (2014 $957 million), representing approximately 82 percent (2014
57 percent) of capital investment.
Divestitures
Divestitures in the first nine months of 2015 were $935 million in the Canadian Operations and $127 million in the USA Operations, which primarily
included the transactions discussed below, as well as the sale of land and properties that do not complement Encanas existing portfolio of assets.
The Canadian Operations included approximately C$558 million ($468 million), after closing adjustments, for the sale of the Companys working
interest in certain assets included in Wheatland located in central and southern Alberta which comprised approximately 1.2 million net acres of land that contained over 6,800 producing wells. Encana retains a working interest in approximately
1.0 million net acres in Wheatland. In addition, the Canadian Operations included approximately C$453 million ($357 million), after closing adjustments, in cash consideration net to Encana for the sale of certain natural gas gathering and
compression assets in northeastern British Columbia to VMLP. In conjunction with the sale, VMLP will undertake the expansion of future midstream services and will also provide natural gas gathering and processing in Montney to Encana and the Cutbank
Ridge Partnership. Further information regarding VMLP can be found in Note 16 to the Interim Condensed Consolidated Financial Statements.
Divestitures in the first nine months of 2014 were $1,850 million in the Canadian Operations and $2,270 million in the USA Operations. The Canadian
Operations primarily included approximately $1.7 billion, after closing adjustments, for the sale of the Companys Bighorn assets. The USA Operations primarily included approximately $1.6 billion, after closing adjustments, for the sale of the
Jonah properties and approximately $497 million for the sale of certain properties in East Texas.
Amounts received from the divestiture
transactions discussed above have been deducted from the respective Canadian and U.S. full cost pools, except for divestitures that resulted in a significant alteration between capitalized costs and proved reserves in the respective 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 third quarter and first nine months of 2014, Encana recognized a gain of approximately $1,024 million,
before tax, on the sale of the Companys Bighorn assets in the Canadian cost centre and allocated goodwill of $257 million. In addition, for the nine months ended September 30, 2014, Encana recognized a gain of approximately $212 million,
before tax, on the sale of the Jonah properties in the U.S. cost centre and allocated goodwill of $68 million.
Acquisitions
Acquisitions in the first nine months of 2014 were $2,961 million in the USA Operations which primarily related to the acquisition of Eagle Ford.
|
|
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
2014 Capital Transactions
The significant acquisition and divestiture transactions below, which occurred during 2014, have impacted the Companys production volume and
operating cash flow variances for the third quarter and first nine months of 2015. A comprehensive discussion of these transactions is included in the annual MD&A for the year ended December 31, 2014.
|
|
|
|
|
Transaction |
|
Location |
|
Closing Date |
|
|
|
Canadian Operations |
|
|
|
|
|
|
|
Divestiture of Encanas remaining investment in PrairieSky (1), (2)
|
|
Alberta |
|
September 26, 2014 |
|
|
|
Sale of Bighorn assets |
|
Alberta |
|
September 30, 2014 |
|
|
|
USA Operations |
|
|
|
|
|
|
|
Sale of Jonah properties |
|
Wyoming |
|
May 12, 2014 |
|
|
|
Sale of East Texas properties |
|
Texas |
|
June 19, 2014 |
|
|
|
Acquisition of properties in the Eagle Ford shale formation |
|
Texas |
|
June 20, 2014 |
|
|
|
Acquisition of Athlon Energy Inc. with assets in the Permian Basin (1) |
|
Texas |
|
November 13, 2014 |
|
(1) |
Transactions involved the disposition or acquisition of common shares and, therefore, were not part of the Companys net acquisition and divestiture
activity for 2014. |
|
(2) |
Encana completed the initial public offering of PrairieSky on May 29, 2014. |
On September 26, 2014, Encana completed the secondary offering of 70.2 million common shares of PrairieSky at a price of C$36.50 per common
share for aggregate gross proceeds of approximately C$2.6 billion. Following the completion of the secondary offering, Encana no longer held an interest in PrairieSky. As the sale of the investment in PrairieSky resulted in a significant alteration
between capitalized costs and proved reserves in the Canadian cost centre, Encana recognized a gain on divestiture of approximately $2.1 billion, before tax. Further information on the PrairieSky transactions can be found in Note 15 to the Interim
Condensed Consolidated Financial Statements.
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended
September 30 |
|
|
|
|
Nine months
ended September 30 |
|
(average daily,
after royalties) |
|
2015 |
|
|
2014 |
|
|
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
|
Natural Gas (MMcf/d) |
|
|
1,547 |
|
|
|
2,199 |
|
|
|
|
|
1,656 |
|
|
|
2,515 |
|
|
|
|
|
|
|
Oil (Mbbls/d) |
|
|
91.9 |
|
|
|
62.1 |
|
|
|
|
|
85.8 |
|
|
|
42.9 |
|
|
|
|
|
|
|
NGLs (Mbbls/d) |
|
|
48.5 |
|
|
|
41.9 |
|
|
|
|
|
43.7 |
|
|
|
37.3 |
|
Total Oil & NGLs (Mbbls/d) |
|
|
140.4 |
|
|
|
104.0 |
|
|
|
|
|
129.5 |
|
|
|
80.2 |
|
Total Production (MBOE/d) |
|
|
398.3 |
|
|
|
470.6 |
|
|
|
|
|
405.6 |
|
|
|
499.3 |
|
|
|
|
|
|
|
Production Mix (%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas |
|
|
65 |
|
|
|
78 |
|
|
|
|
|
68 |
|
|
|
84 |
|
|
|
|
|
|
|
Oil & NGLs |
|
|
35 |
|
|
|
22 |
|
|
|
|
|
32 |
|
|
|
16 |
|
Production Volumes by Play
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30 |
|
|
|
|
Nine months ended September 30 |
|
(average daily, after royalties) |
|
Natural
Gas (MMcf/d) |
|
|
|
|
Oil &
NGLs (Mbbls/d) |
|
|
|
|
Natural
Gas (MMcf/d) |
|
|
|
|
Oil &
NGLs (Mbbls/d) |
|
|
|
2015 |
|
|
2014 |
|
|
|
|
2015 |
|
|
2014 |
|
|
|
|
2015 |
|
|
2014 |
|
|
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Montney (1) |
|
|
711 |
|
|
|
644 |
|
|
|
|
|
21.8 |
|
|
|
20.8 |
|
|
|
|
|
705 |
|
|
|
623 |
|
|
|
|
|
22.3 |
|
|
|
16.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Duvernay |
|
|
26 |
|
|
|
15 |
|
|
|
|
|
4.9 |
|
|
|
2.6 |
|
|
|
|
|
20 |
|
|
|
11 |
|
|
|
|
|
3.6 |
|
|
|
1.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Upstream Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wheatland (2) |
|
|
80 |
|
|
|
291 |
|
|
|
|
|
0.4 |
|
|
|
9.9 |
|
|
|
|
|
89 |
|
|
|
307 |
|
|
|
|
|
1.1 |
|
|
|
10.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Bighorn |
|
|
- |
|
|
|
162 |
|
|
|
|
|
- |
|
|
|
8.7 |
|
|
|
|
|
1 |
|
|
|
212 |
|
|
|
|
|
- |
|
|
|
10.6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Deep Panuke |
|
|
- |
|
|
|
186 |
|
|
|
|
|
- |
|
|
|
- |
|
|
|
|
|
71 |
|
|
|
227 |
|
|
|
|
|
- |
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
Other and emerging (1) |
|
|
59 |
|
|
|
76 |
|
|
|
|
|
0.1 |
|
|
|
0.3 |
|
|
|
|
|
75 |
|
|
|
88 |
|
|
|
|
|
0.1 |
|
|
|
- |
|
Total Canadian Operations |
|
|
876 |
|
|
|
1,374 |
|
|
|
|
|
27.2 |
|
|
|
42.3 |
|
|
|
|
|
961 |
|
|
|
1,468 |
|
|
|
|
|
27.1 |
|
|
|
40.3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
USA Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Eagle Ford |
|
|
48 |
|
|
|
35 |
|
|
|
|
|
46.0 |
|
|
|
37.6 |
|
|
|
|
|
40 |
|
|
|
13 |
|
|
|
|
|
40.6 |
|
|
|
14.3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Permian |
|
|
54 |
|
|
|
- |
|
|
|
|
|
36.7 |
|
|
|
- |
|
|
|
|
|
42 |
|
|
|
- |
|
|
|
|
|
31.0 |
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
DJ Basin |
|
|
55 |
|
|
|
38 |
|
|
|
|
|
16.1 |
|
|
|
11.8 |
|
|
|
|
|
53 |
|
|
|
40 |
|
|
|
|
|
15.2 |
|
|
|
10.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
San Juan |
|
|
15 |
|
|
|
9 |
|
|
|
|
|
6.8 |
|
|
|
3.5 |
|
|
|
|
|
14 |
|
|
|
8 |
|
|
|
|
|
6.7 |
|
|
|
3.4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Upstream Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Piceance |
|
|
311 |
|
|
|
398 |
|
|
|
|
|
3.5 |
|
|
|
4.8 |
|
|
|
|
|
326 |
|
|
|
414 |
|
|
|
|
|
3.6 |
|
|
|
5.2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Haynesville |
|
|
177 |
|
|
|
298 |
|
|
|
|
|
- |
|
|
|
- |
|
|
|
|
|
203 |
|
|
|
331 |
|
|
|
|
|
- |
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
Jonah |
|
|
- |
|
|
|
- |
|
|
|
|
|
- |
|
|
|
0.2 |
|
|
|
|
|
- |
|
|
|
134 |
|
|
|
|
|
- |
|
|
|
2.4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
East Texas |
|
|
- |
|
|
|
21 |
|
|
|
|
|
- |
|
|
|
- |
|
|
|
|
|
- |
|
|
|
77 |
|
|
|
|
|
- |
|
|
|
0.7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Other and emerging |
|
|
11 |
|
|
|
26 |
|
|
|
|
|
4.1 |
|
|
|
3.8 |
|
|
|
|
|
17 |
|
|
|
30 |
|
|
|
|
|
5.3 |
|
|
|
3.1 |
|
Total USA Operations |
|
|
671 |
|
|
|
825 |
|
|
|
|
|
113.2 |
|
|
|
61.7 |
|
|
|
|
|
695 |
|
|
|
1,047 |
|
|
|
|
|
102.4 |
|
|
|
39.9 |
|
Total Production Volumes |
|
|
1,547 |
|
|
|
2,199 |
|
|
|
|
|
140.4 |
|
|
|
104.0 |
|
|
|
|
|
1,656 |
|
|
|
2,515 |
|
|
|
|
|
129.5 |
|
|
|
80.2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Production Volumes Strategic Assets
(1) |
|
|
839 |
|
|
|
694 |
|
|
|
|
|
109.4 |
|
|
|
61.0 |
|
|
|
|
|
807 |
|
|
|
647 |
|
|
|
|
|
97.5 |
|
|
|
33.1 |
|
|
(1) |
Montney has been realigned to include certain production volumes which were previously reported in Other and emerging. |
|
(2) |
Wheatland was previously presented as Clearwater. |
|
|
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
Strategic assets include Montney, Duvernay, Eagle Ford and Permian. Other Upstream Operations includes
production volumes from plays that are not part of the Companys current strategic focus as well as prospective plays that are under appraisal, including the TMS, which is reported within Other and emerging in the USA Operations.
The production volumes associated with the Clearwater lands transferred to PrairieSky were included in Encanas Wheatland play until
September 25, 2014, after which Encana no longer held an interest in PrairieSky.
Natural Gas Production Volumes
In the third quarter of 2015, average natural gas production volumes of 1,547 MMcf/d decreased 652 MMcf/d from 2014. In the first nine months of 2015,
average natural gas production volumes of 1,656 MMcf/d decreased 859 MMcf/d from 2014.
In the third quarter and first nine months of 2015, the
Canadian Operations volumes were lower primarily due to shut-in production at Deep Panuke as a result of the implementation of a seasonal operating strategy during May 2015, the sale of certain assets included in Wheatland in January 2015, and the
sale of the Bighorn assets in the third quarter of 2014, partially offset by successful drilling programs in Montney and Duvernay. In the first nine months of 2015, production volumes were also lower due to a higher water production rate at Deep
Panuke.
In the third quarter of 2015, the USA Operations volumes were lower primarily due to natural declines in Haynesville and Piceance. In the
first nine months of 2015, the USA Operations volumes were lower primarily due to natural declines in Haynesville and Piceance and the sales of the Jonah and East Texas properties in the second quarter of 2014.
Oil and NGL Production Volumes
In the
third quarter of 2015, average oil and NGL production volumes of 140.4 Mbbls/d increased 36.4 Mbbls/d from 2014. In the first nine months of 2015, average oil and NGL production volumes of 129.5 Mbbls/d increased 49.3 Mbbls/d from 2014.
In the third quarter and first nine months of 2015, USA Operations volumes were higher primarily due to the acquisition of the Permian assets in the
fourth quarter of 2014 and successful drilling programs mainly in the Permian and Eagle Ford. In the first nine months of 2015, production volumes were also higher due to the acquisition of Eagle Ford in the second quarter of 2014.
The Canadian Operations volumes were lower in the third quarter and first nine months of 2015 primarily due to the sales of the Bighorn assets and the
Companys investment in PrairieSky in the third quarter of 2014, partially offset by successful drilling programs in Montney and Duvernay.
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
|
|
Canadian Operations
Operating Cash Flow
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30 |
|
|
|
Natural Gas |
|
|
|
|
Oil &
NGLs |
|
|
|
|
Total (1) |
|
($ millions) |
|
2015 |
|
|
2014 |
|
|
|
|
2015 |
|
|
2014 |
|
|
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
|
|
|
|
Revenues, Net of Royalties, excluding Hedging |
|
|
$ 199 |
|
|
|
$ 480 |
|
|
|
|
|
$ 75 |
|
|
|
$ 251 |
|
|
|
|
|
$ 282 |
|
|
|
$ 740 |
|
|
|
|
|
|
|
|
|
|
Realized Financial Hedging Gain (Loss) |
|
|
104 |
|
|
|
20 |
|
|
|
|
|
5 |
|
|
|
(1) |
|
|
|
|
|
109 |
|
|
|
19 |
|
|
|
|
|
|
|
|
|
|
Revenues, Net of Royalties |
|
|
303 |
|
|
|
500 |
|
|
|
|
|
80 |
|
|
|
250 |
|
|
|
|
|
391 |
|
|
|
759 |
|
|
|
|
|
|
|
|
|
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and mineral taxes |
|
|
- |
|
|
|
1 |
|
|
|
|
|
- |
|
|
|
3 |
|
|
|
|
|
- |
|
|
|
4 |
|
|
|
|
|
|
|
|
|
|
Transportation and processing |
|
|
142 |
|
|
|
186 |
|
|
|
|
|
11 |
|
|
|
16 |
|
|
|
|
|
153 |
|
|
|
202 |
|
|
|
|
|
|
|
|
|
|
Operating |
|
|
35 |
|
|
|
66 |
|
|
|
|
|
2 |
|
|
|
8 |
|
|
|
|
|
38 |
|
|
|
76 |
|
|
|
|
|
|
|
|
|
|
Operating Cash Flow |
|
|
$ 126 |
|
|
|
$ 247 |
|
|
|
|
|
$ 67 |
|
|
|
$ 223 |
|
|
|
|
|
$ 200 |
|
|
|
$ 477 |
|
|
|
|
|
|
|
|
|
|
Production Volumes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30 |
|
|
|
Natural
Gas (MMcf/d) |
|
|
|
|
Oil &
NGLs (Mbbls/d) |
|
|
|
|
Total
(MBOE/d) |
|
|
|
2015 |
|
|
2014 |
|
|
|
|
2015 |
|
|
2014 |
|
|
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
|
|
|
|
Production Volumes After Royalties |
|
|
876 |
|
|
|
1,374 |
|
|
|
|
|
27.2 |
|
|
|
42.3 |
|
|
|
|
|
173.2 |
|
|
|
271.4 |
|
|
|
|
|
|
|
|
|
|
Operating Netback (2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30 |
|
|
|
Natural
Gas ($/Mcf) |
|
|
|
|
Oil &
NGLs ($/bbl) |
|
|
|
|
Total
($/BOE) |
|
|
|
2015 |
|
|
2014 |
|
|
|
|
2015 |
|
|
2014 |
|
|
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
|
|
|
|
Revenues, Net of Royalties, excluding Hedging |
|
|
$ 2.48 |
|
|
|
$ 3.78 |
|
|
|
|
|
$ 29.75 |
|
|
|
$ 64.79 |
|
|
|
|
|
$ 17.22 |
|
|
|
$ 29.21 |
|
|
|
|
|
|
|
|
|
|
Realized Financial Hedging Gain (Loss) |
|
|
1.28 |
|
|
|
0.16 |
|
|
|
|
|
2.09 |
|
|
|
(0.31) |
|
|
|
|
|
6.82 |
|
|
|
0.78 |
|
|
|
|
|
|
|
|
|
|
Revenues, Net of Royalties |
|
|
3.76 |
|
|
|
3.94 |
|
|
|
|
|
31.84 |
|
|
|
64.48 |
|
|
|
|
|
24.04 |
|
|
|
29.99 |
|
|
|
|
|
|
|
|
|
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and mineral taxes |
|
|
- |
|
|
|
0.01 |
|
|
|
|
|
(0.02) |
|
|
|
0.67 |
|
|
|
|
|
0.01 |
|
|
|
0.15 |
|
|
|
|
|
|
|
|
|
|
Transportation and processing |
|
|
1.77 |
|
|
|
1.47 |
|
|
|
|
|
3.95 |
|
|
|
4.21 |
|
|
|
|
|
9.55 |
|
|
|
8.10 |
|
|
|
|
|
|
|
|
|
|
Operating |
|
|
0.44 |
|
|
|
0.52 |
|
|
|
|
|
1.22 |
|
|
|
2.05 |
|
|
|
|
|
2.42 |
|
|
|
2.96 |
|
|
|
|
|
|
|
|
|
|
Operating Netback |
|
|
$ 1.55 |
|
|
|
$ 1.94 |
|
|
|
|
|
$ 26.69 |
|
|
|
$ 57.55 |
|
|
|
|
|
$ 12.06 |
|
|
|
$ 18.78 |
|
|
(1) |
Also includes other revenues and expenses, such as third party processing, with no associated volumes. |
|
(2) |
A Non-GAAP measure as defined in the Non-GAAP Measures section of this MD&A. |
|
|
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
Three months ended September 30, 2015 versus September 30, 2014
Operating Cash Flow of $200 million decreased $277 million and was impacted by the following significant items:
|
● |
|
Lower natural gas prices reflected lower benchmark prices, which decreased revenues $107 million. Lower liquids prices reflected lower benchmark prices,
which decreased revenues $86 million. |
|
● |
|
Average natural gas production volumes of 876 MMcf/d were lower by 498 MMcf/d, which decreased revenues $174 million. Average oil and NGL production volumes
of 27.2 Mbbls/d were lower by 15.1 Mbbls/d, which decreased revenues $90 million. Changes in production volumes are discussed in the Production Volumes section of this MD&A. |
|
● |
|
Realized financial hedging gains were $109 million compared to $19 million in 2014. |
|
● |
|
Transportation and processing expense decreased $49 million primarily due to the lower U.S./Canadian dollar exchange rate, the sale of the Bighorn assets in
the third quarter of 2014, the sale of certain assets included in Wheatland in January 2015 and shut-in production at Deep Panuke as a result of the implementation of a seasonal operating strategy during May 2015, partially offset by higher volumes
in Montney. |
|
● |
|
Operating expense decreased $38 million primarily due to the sale of certain assets included in Wheatland in January 2015, the lower U.S./Canadian dollar
exchange rate, the sale of the Bighorn assets in the third quarter of 2014 and lower long-term compensation costs due to the decrease in the Encana share price. |
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
|
|
Operating Cash Flow
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine months ended September 30 |
|
|
|
Natural Gas |
|
|
|
|
Oil &
NGLs |
|
|
|
|
Total (1) |
|
($ millions) |
|
2015 |
|
|
2014 |
|
|
|
|
2015 |
|
|
2014 |
|
|
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
|
|
|
|
Revenues, Net of Royalties, excluding Hedging |
|
|
$ 788 |
|
|
|
$ 2,066 |
|
|
|
|
|
$ 243 |
|
|
|
$ 723 |
|
|
|
|
|
$ 1,044 |
|
|
|
$ 2,811 |
|
|
|
|
|
|
|
|
|
|
Realized Financial Hedging Gain (Loss) |
|
|
364 |
|
|
|
(99) |
|
|
|
|
|
2 |
|
|
|
(6) |
|
|
|
|
|
366 |
|
|
|
(105) |
|
|
|
|
|
|
|
|
|
|
Revenues, Net of Royalties |
|
|
1,152 |
|
|
|
1,967 |
|
|
|
|
|
245 |
|
|
|
717 |
|
|
|
|
|
1,410 |
|
|
|
2,706 |
|
|
|
|
|
|
|
|
|
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and mineral taxes |
|
|
- |
|
|
|
3 |
|
|
|
|
|
- |
|
|
|
10 |
|
|
|
|
|
- |
|
|
|
13 |
|
|
|
|
|
|
|
|
|
|
Transportation and processing |
|
|
463 |
|
|
|
596 |
|
|
|
|
|
38 |
|
|
|
46 |
|
|
|
|
|
501 |
|
|
|
642 |
|
|
|
|
|
|
|
|
|
|
Operating |
|
|
111 |
|
|
|
222 |
|
|
|
|
|
13 |
|
|
|
18 |
|
|
|
|
|
125 |
|
|
|
246 |
|
|
|
|
|
|
|
|
|
|
Operating Cash Flow |
|
|
$ 578 |
|
|
|
$ 1,146 |
|
|
|
|
|
$ 194 |
|
|
|
$ 643 |
|
|
|
|
|
$ 784 |
|
|
|
$ 1,805 |
|
|
|
|
|
|
|
|
|
|
Production Volumes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine months ended September 30 |
|
|
|
Natural
Gas (MMcf/d) |
|
|
|
|
Oil &
NGLs (Mbbls/d) |
|
|
|
|
Total
(MBOE/d) |
|
|
|
2015 |
|
|
2014 |
|
|
|
|
2015 |
|
|
2014 |
|
|
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
|
|
|
|
Production Volumes After Royalties |
|
|
961 |
|
|
|
1,468 |
|
|
|
|
|
27.1 |
|
|
|
40.3 |
|
|
|
|
|
187.2 |
|
|
|
285.0 |
|
|
|
|
|
|
|
|
|
|
Operating Netback (2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine months ended September 30 |
|
|
|
Natural
Gas ($/Mcf) |
|
|
|
|
Oil &
NGLs ($/bbl) |
|
|
|
|
Total
($/BOE) |
|
|
|
2015 |
|
|
2014 |
|
|
|
|
2015 |
|
|
2014 |
|
|
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
|
|
|
|
Revenues, Net of Royalties, excluding Hedging |
|
|
$ 3.00 |
|
|
|
$ 5.14 |
|
|
|
|
|
$ 32.91 |
|
|
|
$ 65.73 |
|
|
|
|
|
$ 20.17 |
|
|
|
$ 35.76 |
|
|
|
|
|
|
|
|
|
|
Realized Financial Hedging Gain (Loss) |
|
|
1.39 |
|
|
|
(0.25) |
|
|
|
|
|
0.25 |
|
|
|
(0.52) |
|
|
|
|
|
7.15 |
|
|
|
(1.34) |
|
|
|
|
|
|
|
|
|
|
Revenues, Net of Royalties |
|
|
4.39 |
|
|
|
4.89 |
|
|
|
|
|
33.16 |
|
|
|
65.21 |
|
|
|
|
|
27.32 |
|
|
|
34.42 |
|
|
|
|
|
|
|
|
|
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and mineral taxes |
|
|
- |
|
|
|
0.01 |
|
|
|
|
|
0.01 |
|
|
|
0.85 |
|
|
|
|
|
0.01 |
|
|
|
0.16 |
|
|
|
|
|
|
|
|
|
|
Transportation and processing |
|
|
1.76 |
|
|
|
1.48 |
|
|
|
|
|
5.07 |
|
|
|
4.19 |
|
|
|
|
|
9.79 |
|
|
|
8.24 |
|
|
|
|
|
|
|
|
|
|
Operating |
|
|
0.42 |
|
|
|
0.55 |
|
|
|
|
|
1.81 |
|
|
|
1.64 |
|
|
|
|
|
2.43 |
|
|
|
3.09 |
|
|
|
|
|
|
|
|
|
|
Operating Netback |
|
|
$ 2.21 |
|
|
|
$ 2.85 |
|
|
|
|
|
$ 26.27 |
|
|
|
$ 58.53 |
|
|
|
|
|
$ 15.09 |
|
|
|
$ 22.93 |
|
|
(1) |
Also includes other revenues and expenses, such as third party processing, with no associated volumes. |
|
(2) |
A Non-GAAP measure as defined in the Non-GAAP Measures section of this MD&A. |
|
|
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
Nine months ended September 30, 2015 versus September 30, 2014
Operating Cash Flow of $784 million decreased $1,021 million and was impacted by the following significant items:
|
● |
|
Lower natural gas prices reflected lower benchmark prices, which decreased revenues $561 million. The average realized natural gas price for production from
Deep Panuke was $9.40 per Mcf compared to $8.71 per Mcf in 2014 and increased the average realized natural gas price $0.50 per Mcf compared to $0.65 per Mcf in 2014. Lower liquids prices reflected lower benchmark prices, which decreased revenues
$243 million. |
|
● |
|
Average natural gas production volumes of 961 MMcf/d were lower by 507 MMcf/d, which decreased revenues $717 million. Average oil and NGL production
volumes of 27.1 Mbbls/d were lower by 13.2 Mbbls/d, which decreased revenues $237 million. Changes in production volumes are discussed in the Production Volumes section of this MD&A. |
|
● |
|
Realized financial hedging gains were $366 million compared to losses of $105 million in 2014. |
|
● |
|
Transportation and processing expense decreased $141 million primarily due to the sale of the Bighorn assets in the third quarter of 2014, the lower
U.S./Canadian dollar exchange rate, the sale of certain assets included in Wheatland in January 2015, and shut-in production at Deep Panuke as a result of the implementation of a seasonal operating strategy during May 2015 and a higher water
production rate, partially offset by higher volumes in Montney. |
|
● |
|
Operating expense decreased $121 million primarily due to the sale of certain assets included in Wheatland in January 2015, the lower U.S./Canadian dollar
exchange rate, the sale of the Bighorn assets in the third quarter of 2014 and lower long-term compensation costs due to the decrease in the Encana share price. |
Other Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30 |
|
|
|
|
Nine months ended September 30 |
|
($ millions, except as indicated) |
|
2015 |
|
|
2014 |
|
|
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
|
Depreciation, depletion & amortization |
|
$ |
64 |
|
|
$ |
166 |
|
|
|
|
$ |
237 |
|
|
$ |
503 |
|
|
|
|
|
|
|
Depletion rate ($/BOE) |
|
|
4.01 |
|
|
|
6.61 |
|
|
|
|
|
4.63 |
|
|
|
6.44 |
|
DD&A decreased in the third quarter and first nine months of 2015 compared to 2014, primarily due to lower
production volumes, the lower U.S./Canadian dollar exchange rate and a lower depletion rate. The depletion rate was impacted by the lower U.S./Canadian dollar exchange rate, and the sales of the Bighorn assets and the Companys investment in
PrairieSky in the third quarter of 2014.
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
|
|
USA Operations
Operating Cash Flow
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30 |
|
|
|
Natural
Gas |
|
|
|
|
Oil &
NGLs |
|
|
|
|
Total (1) |
|
($ millions) |
|
2015 |
|
|
2014 |
|
|
|
|
2015 |
|
|
2014 |
|
|
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
|
|
|
|
Revenues, Net of Royalties, excluding Hedging |
|
$ |
170 |
|
|
$ |
307 |
|
|
|
|
$ |
371 |
|
|
$ |
452 |
|
|
|
|
$ |
547 |
|
|
$ |
769 |
|
|
|
|
|
|
|
|
|
|
Realized Financial Hedging Gain (Loss) |
|
|
54 |
|
|
|
10 |
|
|
|
|
|
54 |
|
|
|
1 |
|
|
|
|
|
108 |
|
|
|
11 |
|
|
|
|
|
|
|
|
|
|
Revenues, Net of Royalties |
|
|
224 |
|
|
|
317 |
|
|
|
|
|
425 |
|
|
|
453 |
|
|
|
|
|
655 |
|
|
|
780 |
|
|
|
|
|
|
|
|
|
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and mineral taxes |
|
|
6 |
|
|
|
(10 |
) |
|
|
|
|
21 |
|
|
|
23 |
|
|
|
|
|
27 |
|
|
|
13 |
|
|
|
|
|
|
|
|
|
|
Transportation and processing |
|
|
152 |
|
|
|
162 |
|
|
|
|
|
3 |
|
|
|
4 |
|
|
|
|
|
155 |
|
|
|
166 |
|
|
|
|
|
|
|
|
|
|
Operating |
|
|
39 |
|
|
|
50 |
|
|
|
|
|
103 |
|
|
|
44 |
|
|
|
|
|
142 |
|
|
|
96 |
|
|
|
|
|
|
|
|
|
|
Operating Cash Flow |
|
$ |
27 |
|
|
$ |
115 |
|
|
|
|
$ |
298 |
|
|
$ |
382 |
|
|
|
|
$ |
331 |
|
|
$ |
505 |
|
Production Volumes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30 |
|
|
|
Natural Gas (MMcf/d) |
|
|
|
|
Oil & NGLs
(Mbbls/d) |
|
|
|
|
Total
(MBOE/d) |
|
|
|
2015 |
|
|
2014 |
|
|
|
|
2015 |
|
|
2014 |
|
|
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
|
|
|
|
Production Volumes After Royalties |
|
|
671 |
|
|
|
825 |
|
|
|
|
|
113.2 |
|
|
|
61.7 |
|
|
|
|
|
225.1 |
|
|
|
199.2 |
|
Operating Netback (2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30 |
|
|
|
Natural
Gas ($/Mcf) |
|
|
|
|
Oil & NGLs
($/bbl) |
|
|
|
|
Total
($/BOE) |
|
|
|
2015 |
|
|
2014 |
|
|
|
|
2015 |
|
|
2014 |
|
|
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
|
|
|
|
Revenues, Net of Royalties, excluding Hedging |
|
$ |
2.75 |
|
|
$ |
4.05 |
|
|
|
|
$ |
35.66 |
|
|
$ |
79.43 |
|
|
|
|
$ |
26.13 |
|
|
$ |
41.38 |
|
|
|
|
|
|
|
|
|
|
Realized Financial Hedging Gain (Loss) |
|
|
0.88 |
|
|
|
0.12 |
|
|
|
|
|
5.17 |
|
|
|
0.25 |
|
|
|
|
|
5.21 |
|
|
|
0.58 |
|
|
|
|
|
|
|
|
|
|
Revenues, Net of Royalties |
|
|
3.63 |
|
|
|
4.17 |
|
|
|
|
|
40.83 |
|
|
|
79.68 |
|
|
|
|
|
31.34 |
|
|
|
41.96 |
|
|
|
|
|
|
|
|
|
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and mineral taxes |
|
|
0.11 |
|
|
|
(0.14 |
) |
|
|
|
|
1.95 |
|
|
|
4.18 |
|
|
|
|
|
1.30 |
|
|
|
0.72 |
|
|
|
|
|
|
|
|
|
|
Transportation and processing |
|
|
2.47 |
|
|
|
2.13 |
|
|
|
|
|
0.31 |
|
|
|
0.63 |
|
|
|
|
|
7.52 |
|
|
|
9.03 |
|
|
|
|
|
|
|
|
|
|
Operating |
|
|
0.62 |
|
|
|
0.65 |
|
|
|
|
|
9.95 |
|
|
|
7.80 |
|
|
|
|
|
6.85 |
|
|
|
5.12 |
|
|
|
|
|
|
|
|
|
|
Operating Netback |
|
$ |
0.43 |
|
|
$ |
1.53 |
|
|
|
|
$ |
28.62 |
|
|
$ |
67.07 |
|
|
|
|
$ |
15.67 |
|
|
$ |
27.09 |
|
|
(1) |
Also includes other revenues and expenses, such as third party processing, with no associated volumes. |
|
(2) |
A Non-GAAP measure as defined in the Non-GAAP Measures section of this MD&A. |
|
|
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
Three months ended September 30, 2015 versus September 30, 2014
Operating Cash Flow of $331 million decreased $174 million and was impacted by the following significant items:
|
● |
|
Lower natural gas prices reflected lower benchmark prices, which decreased revenues $73 million. Lower liquids prices reflected lower benchmark prices, which
decreased revenues $310 million. |
|
● |
|
Average natural gas production volumes of 671 MMcf/d were lower by 154 MMcf/d, which decreased revenues $64 million. Average oil and NGL production
volumes of 113.2 Mbbls/d were higher by 51.5 Mbbls/d, which increased revenues $229 million. Changes in production volumes are discussed in the Production Volumes section of this MD&A. |
|
● |
|
Realized financial hedging gains were $108 million compared to $11 million in 2014. |
|
● |
|
Operating expense increased $46 million primarily due to the acquisition of the Permian assets in the fourth quarter of 2014 and successful drilling programs
in the Permian and Eagle Ford. |
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
|
|
Operating Cash Flow
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine months ended September 30 |
|
|
|
Natural
Gas |
|
|
|
|
Oil & NGLs |
|
|
|
|
Total (1) |
|
($ millions) |
|
2015 |
|
|
2014 |
|
|
|
|
2015 |
|
|
2014 |
|
|
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
|
|
|
|
Revenues, Net of Royalties, excluding Hedging |
|
$ |
511 |
|
|
$ |
1,366 |
|
|
|
|
$ |
1,080 |
|
|
$ |
846 |
|
|
|
|
$ |
1,609 |
|
|
$ |
2,234 |
|
|
|
|
|
|
|
|
|
|
Realized Financial Hedging Gain (Loss) |
|
|
166 |
|
|
|
(98 |
) |
|
|
|
|
97 |
|
|
|
(5 |
) |
|
|
|
|
263 |
|
|
|
(103 |
) |
|
|
|
|
|
|
|
|
|
Revenues, Net of Royalties |
|
|
677 |
|
|
|
1,268 |
|
|
|
|
|
1,177 |
|
|
|
841 |
|
|
|
|
|
1,872 |
|
|
|
2,131 |
|
|
|
|
|
|
|
|
|
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and mineral taxes |
|
|
15 |
|
|
|
33 |
|
|
|
|
|
57 |
|
|
|
51 |
|
|
|
|
|
72 |
|
|
|
84 |
|
|
|
|
|
|
|
|
|
|
Transportation and processing |
|
|
445 |
|
|
|
502 |
|
|
|
|
|
9 |
|
|
|
4 |
|
|
|
|
|
454 |
|
|
|
506 |
|
|
|
|
|
|
|
|
|
|
Operating |
|
|
134 |
|
|
|
183 |
|
|
|
|
|
282 |
|
|
|
64 |
|
|
|
|
|
418 |
|
|
|
249 |
|
|
|
|
|
|
|
|
|
|
Operating Cash Flow |
|
$ |
83 |
|
|
$ |
550 |
|
|
|
|
$ |
829 |
|
|
$ |
722 |
|
|
|
|
$ |
928 |
|
|
$ |
1,292 |
|
Production Volumes
|
|
|
|
Nine months ended September 30 |
|
|
|
Natural
Gas (MMcf/d) |
|
|
|
|
Oil & NGLs
(Mbbls/d) |
|
|
|
|
Total
(MBOE/d) |
|
|
|
2015 |
|
|
2014 |
|
|
|
|
2015 |
|
|
2014 |
|
|
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
|
|
|
|
Production Volumes After Royalties |
|
|
695 |
|
|
|
1,047 |
|
|
|
|
|
102.4 |
|
|
|
39.9 |
|
|
|
|
|
218.4 |
|
|
|
214.3 |
|
Operating Netback (2) |
|
|
|
Nine months ended September 30 |
|
|
|
Natural
Gas ($/Mcf) |
|
|
|
|
Oil & NGLs
($/bbl) |
|
|
|
|
Total
($/BOE) |
|
|
|
2015 |
|
|
2014 |
|
|
|
|
2015 |
|
|
2014 |
|
|
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
|
|
|
|
Revenues, Net of Royalties, excluding Hedging |
|
$ |
2.69 |
|
|
$ |
4.78 |
|
|
|
|
$ |
38.65 |
|
|
$ |
77.63 |
|
|
|
|
$ |
26.69 |
|
|
$ |
37.81 |
|
|
|
|
|
|
|
|
|
|
Realized Financial Hedging Gain (Loss) |
|
|
0.88 |
|
|
|
(0.34 |
) |
|
|
|
|
3.46 |
|
|
|
(0.45 |
) |
|
|
|
|
4.42 |
|
|
|
(1.76 |
) |
|
|
|
|
|
|
|
|
|
Revenues, Net of Royalties |
|
|
3.57 |
|
|
|
4.44 |
|
|
|
|
|
42.11 |
|
|
|
77.18 |
|
|
|
|
|
31.11 |
|
|
|
36.05 |
|
|
|
|
|
|
|
|
|
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and mineral taxes |
|
|
0.08 |
|
|
|
0.11 |
|
|
|
|
|
2.01 |
|
|
|
4.72 |
|
|
|
|
|
1.20 |
|
|
|
1.44 |
|
|
|
|
|
|
|
|
|
|
Transportation and processing |
|
|
2.35 |
|
|
|
1.76 |
|
|
|
|
|
0.32 |
|
|
|
0.33 |
|
|
|
|
|
7.62 |
|
|
|
8.64 |
|
|
|
|
|
|
|
|
|
|
Operating |
|
|
0.71 |
|
|
|
0.64 |
|
|
|
|
|
10.09 |
|
|
|
5.87 |
|
|
|
|
|
6.98 |
|
|
|
4.22 |
|
|
|
|
|
|
|
|
|
|
Operating Netback |
|
$ |
0.43 |
|
|
$ |
1.93 |
|
|
|
|
$ |
29.69 |
|
|
$ |
66.26 |
|
|
|
|
$ |
15.31 |
|
|
$ |
21.75 |
|
|
(1) |
Also includes other revenues and expenses, such as third party processing, with no associated volumes. |
|
(2) |
A Non-GAAP measure as defined in the Non-GAAP Measures section of this MD&A. |
|
|
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
Nine months ended September 30, 2015 versus September 30, 2014
Operating Cash Flow of $928 million decreased $364 million and was impacted by the following significant items:
|
● |
|
Lower natural gas prices reflected lower benchmark prices, which decreased revenues $350 million. Lower liquids prices reflected lower benchmark prices,
which decreased revenues $569 million. |
|
● |
|
Average natural gas production volumes of 695 MMcf/d were lower by 352 MMcf/d, which decreased revenues $505 million. Average oil and NGL production volumes
of 102.4 Mbbls/d were higher by 62.5 Mbbls/d, which increased revenues $803 million. Changes in production volumes are discussed in the Production Volumes section of this MD&A. |
|
● |
|
Realized financial hedging gains were $263 million compared to losses of $103 million in 2014. |
|
● |
|
Transportation and processing expense decreased $52 million primarily due to divestitures, which includes the sales of the Jonah and East Texas properties in
the second quarter of 2014, partially offset by the acquisitions of Eagle Ford and the Permian assets in the second and fourth quarters of 2014, respectively. |
|
● |
|
Operating expense increased $169 million primarily due to the acquisitions of Eagle Ford and the Permian assets in the second and fourth quarters of 2014,
respectively, and successful drilling programs in these plays during 2015, partially offset by the sales of the Jonah and East Texas properties in the second quarter of 2014 and lower long-term compensation costs due to the decrease in the Encana
share price. |
Other Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30 |
|
|
|
|
Nine months ended September 30 |
|
($ millions, except as indicated) |
|
2015 |
|
|
2014 |
|
|
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
|
Depreciation, depletion & amortization |
|
|
$ 265 |
|
|
|
$ 279 |
|
|
|
|
|
$ 902 |
|
|
|
$ 694 |
|
|
|
|
|
|
|
Depletion rate ($/BOE) |
|
|
12.77 |
|
|
|
15.22 |
|
|
|
|
|
14.92 |
|
|
|
11.86 |
|
|
|
|
|
|
|
Impairments |
|
|
1,671 |
|
|
|
- |
|
|
|
|
|
5,668 |
|
|
|
- |
|
DD&A decreased in the third quarter of 2015 compared to 2014, primarily due to a lower depletion rate, partially
offset by higher production volumes. The depletion rate was lower primarily due to the ceiling test impairments recognized in the first six months of 2015, partially offset by the acquisition of the Permian assets in the fourth quarter of 2014.
DD&A increased in the first nine months of 2015 compared to 2014, primarily due to a higher depletion rate. The depletion rate was higher primarily due to the acquisitions of Eagle Ford and the Permian assets in the second and fourth quarters of
2014, respectively, partially offset by the ceiling test impairments recognized in the first six months of 2015 and a decrease in proved reserves as a result of the sale of the Jonah properties in the second quarter of 2014.
In the third quarter and first nine months of 2015, the USA Operations recognized before-tax non-cash ceiling test impairments of $1,671 million and
$5,668 million, respectively. The impairments primarily resulted from the decline in the 12-month average trailing commodity prices, which reduced the USA Operations proved reserves volumes and values as calculated under SEC requirements.
The 12-month average trailing prices used in the ceiling test calculations were based on the benchmark prices below. The benchmark prices were adjusted
for basis differentials to determine local reference prices, transportation costs and tariffs, heat content and quality.
|
|
|
|
|
|
|
|
|
|
|
Natural Gas |
|
|
Oil & NGLs |
|
|
|
Henry Hub ($/MMBtu) |
|
|
WTI
($/bbl) |
|
|
|
|
12-Month Average Trailing Reserves Pricing (1) |
|
|
|
|
|
|
|
|
|
|
|
September 30, 2015 |
|
|
3.05 |
|
|
|
59.21 |
|
|
|
|
December 31, 2014 |
|
|
4.34 |
|
|
|
94.99 |
|
|
|
|
September 30, 2014 |
|
|
4.24 |
|
|
|
99.08 |
|
|
(1) |
All prices were held constant in all future years when estimating reserves. |
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
|
|
Market Optimization
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30 |
|
|
|
|
Nine months ended September 30 |
|
($ millions) |
|
2015 |
|
|
2014 |
|
|
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
|
Revenues |
|
$ |
66 |
|
|
$ |
486 |
|
|
|
|
$ |
293 |
|
|
$ |
890 |
|
|
|
|
|
|
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating |
|
|
4 |
|
|
|
11 |
|
|
|
|
|
28 |
|
|
|
37 |
|
|
|
|
|
|
|
Purchased product |
|
|
60 |
|
|
|
474 |
|
|
|
|
|
260 |
|
|
|
844 |
|
|
|
|
|
|
|
Depreciation, depletion and amortization |
|
|
- |
|
|
|
- |
|
|
|
|
|
- |
|
|
|
4 |
|
|
|
|
|
|
|
|
|
$ |
2 |
|
|
$ |
1 |
|
|
|
|
$ |
5 |
|
|
$ |
5 |
|
Market
Optimization revenues and purchased product expense relate to activities that provide operational flexibility for transportation commitments, product type, delivery points and customer diversification. Revenues and purchased product expense
decreased in the third quarter and first nine months of 2015 compared to 2014 primarily due to lower commodity prices and lower third-party volumes resulting from transitional services related to the Companys divestiture activity.
Corporate and Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30 |
|
|
|
|
Nine months ended September 30 |
|
($ millions) |
|
2015 |
|
|
2014 |
|
|
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
|
Revenues |
|
$ |
200 |
|
|
$ |
260 |
|
|
|
|
$ |
(184 |
) |
|
$ |
38 |
|
|
|
|
|
|
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transportation and processing |
|
|
11 |
|
|
|
2 |
|
|
|
|
|
4 |
|
|
|
1 |
|
|
|
|
|
|
|
Operating |
|
|
6 |
|
|
|
7 |
|
|
|
|
|
17 |
|
|
|
25 |
|
|
|
|
|
|
|
Depreciation, depletion and amortization |
|
|
23 |
|
|
|
31 |
|
|
|
|
|
73 |
|
|
|
93 |
|
|
|
|
|
|
|
|
|
$ |
160 |
|
|
$ |
220 |
|
|
|
|
$ |
(278 |
) |
|
$ |
(81 |
) |
Revenues mainly include unrealized hedging gains or losses recorded on derivative financial contracts which result from
the volatility in forward curves of commodity prices and changes in the balance of unsettled contracts between periods. Transportation and processing expense reflects unrealized financial hedging gains or losses related to the Companys power
financial derivative contracts. DD&A includes amortization of corporate assets, such as computer equipment, office buildings, furniture and leasehold improvements.
Corporate and Other results include revenues and operating expenses related to the sublease of office space in The Bow office building. Further
information on The Bow office sublease can be found in Note 11 to the Interim Condensed Consolidated Financial Statements.
|
|
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30 |
|
|
|
|
Nine months ended September 30 |
|
($ millions) |
|
2015 |
|
|
2014 |
|
|
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
|
Accretion of asset retirement obligation |
|
$ |
11 |
|
|
$ |
13 |
|
|
|
|
$ |
34 |
|
|
$ |
39 |
|
|
|
|
|
|
|
Administrative |
|
|
61 |
|
|
|
69 |
|
|
|
|
|
217 |
|
|
|
269 |
|
|
|
|
|
|
|
Interest |
|
|
105 |
|
|
|
133 |
|
|
|
|
|
508 |
|
|
|
402 |
|
|
|
|
|
|
|
Foreign exchange (gain) loss, net |
|
|
348 |
|
|
|
202 |
|
|
|
|
|
918 |
|
|
|
254 |
|
|
|
|
|
|
|
(Gain) loss on divestitures |
|
|
2 |
|
|
|
(3,239 |
) |
|
|
|
|
(14 |
) |
|
|
(3,442 |
) |
|
|
|
|
|
|
Other |
|
|
(3 |
) |
|
|
- |
|
|
|
|
|
2 |
|
|
|
8 |
|
|
|
|
|
|
|
|
|
$ |
524 |
|
|
$ |
(2,822 |
) |
|
|
|
$ |
1,665 |
|
|
$ |
(2,470 |
) |
Administrative expense in the first nine months of 2015 decreased from 2014 primarily due to lower long-term
compensation costs due to the decrease in the Encana share price and the lower U.S./Canadian dollar exchange rate, partially offset by higher restructuring costs. During the second quarter of 2015, Encana revised its plans to align the
organizational structure in continued support of the Companys strategy, which resulted in restructuring costs of $28 million and $58 million for the third quarter and first nine months of 2015, respectively. Restructuring costs attributable to
work force reductions associated with the 2013 restructuring were nil and $1 million in the third quarter and first nine months of 2015, respectively, compared with $7 million and $29 million, respectively, for 2014.
Interest expense in the first nine months of 2015 increased from 2014 primarily due to a one-time interest payment of approximately $165 million
resulting from the April 2015 early debt redemptions, partially offset by lower interest on debt following these redemptions.
Foreign exchange
gains and losses result from the impact of the fluctuations in the Canadian to U.S. dollar exchange rate. In the third quarter of 2015 compared to 2014, the Company recorded higher foreign exchange losses on settlements, other monetary revaluations
and the translation of U.S. dollar long-term debt issued from Canada, partially offset by foreign exchange gains on the translation of intercompany notes. In the first nine months of 2015 compared to 2014, Encana recorded higher foreign exchange
losses on the translation of U.S. dollar long-term debt issued from Canada and on settlements.
Gain on divestitures in the first nine months of
2015 primarily includes a before tax gain on the sale of the Encana Place office building in Calgary. Gain on divestitures in the first nine months of 2014 primarily includes the before tax impact of the sales of Encanas investment in
PrairieSky, the Bighorn assets and the Jonah properties, as discussed in the Net Capital Investment section of this MD&A.
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
|
|
Income Tax
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30 |
|
|
|
|
Nine months ended September 30 |
|
($ millions) |
|
2015 |
|
|
2014 |
|
|
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
|
Current Income Tax (Recovery) |
|
$ |
(19 |
) |
|
$ |
244 |
|
|
|
|
$ |
(38 |
) |
|
$ |
241 |
|
|
|
|
|
|
|
Deferred Income Tax (Recovery) |
|
|
(576 |
) |
|
|
505 |
|
|
|
|
|
(2,442 |
) |
|
|
825 |
|
|
|
|
|
|
|
Income Tax Expense (Recovery) |
|
$ |
(595 |
) |
|
$ |
749 |
|
|
|
|
$ |
(2,480 |
) |
|
$ |
1,066 |
|
The current income tax recovery of $38 million in the first nine months of 2015 was primarily due to amounts in respect
of prior periods while the current income tax expense of $241 million in the first nine months of 2014 was primarily due to current taxes incurred on divestitures. Total income tax recovery in the first nine months of 2015 was primarily due to lower
net earnings before tax. The net earnings variances are discussed in the Financial Results section of this MD&A.
Encanas interim income
tax expense is determined using the estimated annual effective income tax rate applied to year-to-date net earnings before tax plus the effect of legislative changes, including the 2015 Alberta general corporate income tax rate increase, and amounts
in respect of prior periods. The estimated annual effective income tax rate is impacted by expected annual earnings, statutory rate and other foreign differences, non-taxable capital gains and losses, tax differences on divestitures and
transactions, and partnership tax allocations in excess of funding. The Companys effective tax rate for the first nine months of 2015 is higher than 2014 primarily as a result of changes in expected annual earnings and the gain on divestitures
in 2014.
Tax interpretations, regulations and legislation in the various jurisdictions in which the Company and its Subsidiaries operate are
subject to change. As a result, there are tax matters under review. The Company believes that the provision for taxes is adequate.
|
|
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
|
Liquidity and Capital Resources |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30 |
|
|
|
|
Nine months ended September 30 |
|
($ millions) |
|
2015 |
|
|
2014 |
|
|
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
|
Net Cash From (Used In) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities |
|
$ |
453 |
|
|
$ |
696 |
|
|
|
|
$ |
1,233 |
|
|
$ |
2,406 |
|
|
|
|
|
|
|
Investing activities |
|
|
(544 |
) |
|
|
3,805 |
|
|
|
|
|
(957 |
) |
|
|
1,870 |
|
|
|
|
|
|
|
Financing activities |
|
|
(36 |
) |
|
|
(95 |
) |
|
|
|
|
(238 |
) |
|
|
231 |
|
|
|
|
|
|
|
Foreign exchange gain (loss) on cash and cash equivalents held in foreign currency |
|
|
(17 |
) |
|
|
(90 |
) |
|
|
|
|
(24 |
) |
|
|
(99 |
) |
|
|
|
|
|
|
Increase (Decrease) in Cash and Cash Equivalents |
|
$ |
(144 |
) |
|
$ |
4,316 |
|
|
|
|
$ |
14 |
|
|
$ |
4,408 |
|
|
|
|
|
|
|
Cash and Cash Equivalents, End of Period |
|
$ |
352 |
|
|
$ |
6,974 |
|
|
|
|
$ |
352 |
|
|
$ |
6,974 |
|
Operating Activities
Net cash from operating activities in the
third quarter of 2015 of $453 million decreased $243 million from 2014 primarily as a result of the Cash Flow variances discussed in the Financial Results section of this MD&A. In the third quarter of 2015, the net change in non-cash working
capital was a surplus of $100 million compared to $155 million in 2014.
Net cash from operating activities in the first nine months of 2015 of
$1,233 million decreased $1,173 million from 2014 primarily as a result of the Cash Flow variances discussed in the Financial Results section of this MD&A. In the first nine months of 2015, the net change in non-cash working capital was a
surplus of $204 million compared to $132 million in 2014.
The Company had a working capital surplus of $277 million at September 30, 2015
compared to $455 million at December 31, 2014. The decrease in working capital is primarily due to a decrease in accounts receivable and accrued revenues and risk management assets, partially offset by a decrease in accounts payable and accrued
liabilities. At September 30, 2015, working capital included cash and cash equivalents of $352 million compared to $338 million at December 31, 2014. Encana expects it will continue to meet the payment terms of its suppliers.
Investing Activities
Net cash used in investing activities in the first nine months of 2015 was $957 million compared to net cash from investing activities of $1,870 million
in 2014. The change was primarily due to lower proceeds from divestitures and the sale of the Companys investment in PrairieSky in 2014, partially offset by the acquisition of Eagle Ford in 2014. Further information on acquisitions and
divestitures can be found in the Net Capital Investment section of this MD&A.
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
|
|
Financing Activities
Net cash used in financing activities in the
first nine months of 2015 was $238 million compared to net cash from financing activities of $231 million in 2014. The change was primarily due to the sale of a noncontrolling interest in PrairieSky in the second quarter of 2014, partially offset by
proceeds from the issuance of common shares pursuant to the Share Offering in the first quarter of 2015.
Credit Facilities
The following table outlines the Companys committed revolving bank credit facilities at September 30, 2015:
|
|
|
|
|
|
|
|
|
|
|
|
|
($ billions) |
|
Capacity |
|
|
Unused |
|
|
Maturity Date |
|
|
|
|
|
Committed Revolving Bank Credit Facilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Encana Credit Facility (1) |
|
|
3.0 |
|
|
|
1.6 |
|
|
|
July 2020 |
|
|
|
|
|
U.S. Subsidiary Credit Facility |
|
|
1.5 |
|
|
|
1.5 |
|
|
|
July 2020 |
|
|
(1) |
At September 30, 2015, $1.4 billion fully supported the U.S. Commercial Paper program, as discussed in the Long-Term Debt section below.
|
Encana is currently in compliance with, and expects that it will continue to be in compliance with, all financial covenants under
its credit facility agreements. Management monitors Debt to Adjusted Capitalization as a proxy for Encanas financial covenant under its credit facility agreements which require 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 Companys January 1, 2012
adoption of U.S. GAAP. Debt to Adjusted Capitalization was 30 percent at September 30, 2015 and December 31, 2014.
Long-Term
Debt
Encanas long-term debt, excluding the current portion, totaled $6,128 million at September 30, 2015 and $7,340 million
at December 31, 2014. There was no current portion of long-term debt outstanding at September 30, 2015 or December 31, 2014.
On
April 6, 2015, the Company used the net proceeds from the Share Offering and cash on hand to complete the redemption of its $700 million 5.90 percent notes due December 1, 2017 and its C$750 million 5.80 percent medium-term notes due
January 18, 2018. The note redemptions required an aggregate one-time early interest payment of approximately $165 million and is expected to save Encana a gross amount of approximately $205 million in future interest expense, based on foreign
exchange and treasury rates at the time of the redemptions.
During the first quarter of 2015, Encana implemented a U.S. Commercial Paper
(U.S. CP) program which is fully supported by the Companys revolving credit facility. At September 30, 2015, Encana had an outstanding balance of $1,414 million which reflected U.S. CP issuances that had an average term of 28
days and a weighted average interest rate of 0.64 percent. Management expects these amounts will continue to be supported by the revolving credit facility that has no repayment requirements within the next year. At December 31, 2014, Encana had
an outstanding balance of $1,277 million under the Companys revolving credit facility, which reflected principal obligations related to LIBOR loans maturing at various dates with a weighted average interest rate of 1.62 percent. During the
first quarter of 2015, Encana repaid the outstanding balance relating to LIBOR loans using proceeds from the U.S. CP program and cash on hand.
Encana has the flexibility to refinance maturing long-term debt or repay debt maturities from existing sources of liquidity. Encanas primary
sources of liquidity include cash and cash equivalents, revolving bank credit facilities, working capital, operating cash flow and proceeds from asset divestitures.
|
|
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
Shelf Prospectus
On June 27, 2014, Encana filed a short form base shelf prospectus, whereby the Company may issue from time to time up to $6.0 billion, or the
equivalent in foreign currencies, of debt securities, common shares, preferred shares, subscription receipts, warrants and units in Canada and/or the U.S. On March 5, 2015, the Company filed a prospectus supplement to the base shelf prospectus
for the issuance of 85,616,500 common shares of Encana and granted an over-allotment option for up to an additional 12,842,475 common shares of Encana at a price of C$14.60 per common share, pursuant to an underwriting agreement. The Share Offering
of 98,458,975 common shares of Encana was completed during March 2015 for aggregate gross proceeds of approximately C$1.44 billion ($1.13 billion). After deducting underwriters fees and costs of the Share Offering, the net proceeds received
were approximately C$1.39 billion ($1.09 billion). At September 30, 2015, $4.9 billion, or the equivalent in foreign currencies, remained accessible under the shelf prospectus, the availability of which is dependent upon market conditions. The
shelf prospectus expires in July 2016.
Outstanding Share Data
|
|
|
|
|
|
|
|
|
|
|
|
|
(millions) |
|
December 31, 2014 |
|
|
September 30, 2015 |
|
|
November 6, 2015 |
|
|
|
|
|
Common Shares Outstanding |
|
|
741.2 |
|
|
|
845.7 |
|
|
|
845.7 |
|
|
|
|
|
Stock Options with TSARs attached (1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding |
|
|
21.3 |
|
|
|
19.7 |
|
|
|
19.0 |
|
|
|
|
|
Exercisable |
|
|
10.0 |
|
|
|
10.9 |
|
|
|
10.4 |
|
|
(1) |
A Tandem Stock Appreciation Right (TSAR) gives the option holder the right to receive a cash payment equal to the excess of the market price of
Encanas common shares at the time of exercise over the original grant price. |
During the first quarter of 2015, Encana
issued common shares pursuant to the Share Offering as discussed above.
During the first nine months of 2015, Encana issued 6,115,535 common shares
under the Companys dividend reinvestment plan (DRIP) compared with 164,840 common shares in 2014. The number of common shares issued under the DRIP increased in the first nine months of 2015 primarily as a result of Encanas
February 25, 2015 announcement that, effective with the dividend payable on March 31, 2015, any future dividends in conjunction with the DRIP will be issued from its treasury with a two percent discount to the average market price of the
common shares unless otherwise announced by the Company via news release.
Dividends
Encana pays quarterly dividends to shareholders at the discretion of the Board.
|
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|
|
|
|
|
|
|
|
|
Three months ended September 30 |
|
|
|
|
Nine months ended September 30 |
|
($ millions, except as indicated) |
|
2015 |
|
|
2014 |
|
|
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
|
Dividend Payments |
|
|
$ 59 |
|
|
|
$ 52 |
|
|
|
|
|
$ 166 |
|
|
|
$ 156 |
|
|
|
|
|
|
|
Dividend Payments ($/share) |
|
|
0.07 |
|
|
|
0.07 |
|
|
|
|
|
0.21 |
|
|
|
0.21 |
|
The dividends paid in the third quarter and first nine months of 2015 included $21 million and $53 million,
respectively, in common shares issued in lieu of cash dividends under the DRIP compared to $1 million and $4 million, respectively, for 2014. Common shares issued in the Share Offering were not eligible to receive the dividend that was paid during
the first quarter of 2015.
On November 11, 2015, the Board declared a dividend of $0.07 per share payable on December 31, 2015 to common
shareholders of record as of December 15, 2015.
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
|
|
Capital Structure
The Companys capital structure consists of total shareholders equity plus long-term debt, including the current portion. The Companys
objectives when managing its capital structure are to maintain financial flexibility to preserve Encanas access to capital markets and its ability to meet financial obligations and finance internally generated growth, as well as potential
acquisitions. Encana has a long-standing practice of maintaining capital discipline and managing and adjusting its capital structure according to market conditions to maintain flexibility while achieving the Companys objectives.
To manage the capital structure, the Company may adjust capital spending, adjust dividends paid to shareholders, issue new shares, issue new debt or
repay existing debt. In managing its capital structure, the Company monitors the following non-GAAP financial metrics as indicators of its overall financial strength, which are defined in the Non-GAAP Measures section of this MD&A.
|
|
|
|
|
|
|
September 30, 2015 |
|
December 31, 2014 |
|
|
|
Debt to Debt Adjusted Cash Flow |
|
3.1x |
|
2.1x |
|
|
|
Debt to Adjusted Capitalization |
|
30% |
|
30% |
|
|
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
|
Commitments and Contingencies |
Commitments
The following table outlines the Companys commitments at September 30, 2015:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected Future Payments |
|
($ millions, undiscounted) |
|
2015 |
|
|
2016 |
|
|
2017 |
|
|
2018 |
|
|
2019 |
|
|
Thereafter |
|
|
Total |
|
|
|
|
|
|
|
|
|
Transportation and Processing |
|
$ |
210 |
|
|
$ |
795 |
|
|
$ |
778 |
|
|
$ |
790 |
|
|
$ |
672 |
|
|
$ |
3,037 |
|
|
$ |
6,282 |
|
|
|
|
|
|
|
|
|
Drilling and Field Services |
|
|
62 |
|
|
|
151 |
|
|
|
107 |
|
|
|
54 |
|
|
|
18 |
|
|
|
22 |
|
|
|
414 |
|
|
|
|
|
|
|
|
|
Operating Leases |
|
|
9 |
|
|
|
29 |
|
|
|
24 |
|
|
|
23 |
|
|
|
11 |
|
|
|
23 |
|
|
|
119 |
|
|
|
|
|
|
|
|
|
Commitments |
|
$ |
281 |
|
|
$ |
975 |
|
|
$ |
909 |
|
|
$ |
867 |
|
|
$ |
701 |
|
|
$ |
3,082 |
|
|
$ |
6,815 |
|
Included in Transportation and Processing in the table above are certain commitments associated with midstream service
agreements with VMLP. Additional information can be found in Note 16 to the Interim Condensed Consolidated Financial Statements. Encana also has significant development commitments with joint venture partners, a portion of which may be satisfied by
the Drilling and Field Services commitments included in the table above.
Further to the Commitments disclosed above, Encana also has obligations
related to its risk management program and to fund its defined benefit pension and other post-employment benefit plans. Contractual obligations arising from long-term debt, asset retirement obligations, The Bow office building and capital leases are
recognized on the Companys balance sheet. Further information can be found in the note disclosures to the Interim Condensed Consolidated Financial Statements.
Announced divestiture transactions can reduce certain commitments and obligations disclosed above. The Company expects to fund its 2015 commitments and
obligations from Cash Flow and cash and cash equivalents.
Contingencies
Encana is involved in various legal claims and actions arising in the course of the Companys 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 Encanas financial position, cash flows or results of operations. If an unfavourable outcome were to occur, there exists the
possibility of a material adverse impact on the Companys consolidated net earnings or loss in the period in which the outcome is determined. Accruals for litigation and claims are recognized if the Company determines that the loss is probable
and the amount can be reasonably estimated. The Company believes it has made adequate provision for such legal claims.
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
|
|
Encanas business, prospects, financial condition, results of operations and cash flows, and in some cases its
reputation, are impacted by risks that can be categorized as follows:
|
● |
|
environmental, regulatory, reputational and safety risks. |
Encana aims to strengthen its position as a leading North American energy producer and grow shareholder value through a disciplined focus on generating
profitable growth. Encana continues to focus on developing a balanced portfolio of low-risk and low-cost long-life plays, enabling the Company to respond to market uncertainties. Management adjusts financial and operational risk strategies to
proactively respond to changing economic conditions and to mitigate or reduce risk.
Issues that can affect Encanas reputation are generally
strategic or emerging issues that can be identified early and then appropriately managed, but can also include unforeseen issues that must be managed on a more urgent basis. Encana takes a proactive approach to the identification and management of
issues that affect the Companys reputation and has established appropriate policies, procedures, guidelines and responsibilities for identifying and managing these risks.
Financial Risks
Encana defines
financial risks as the risk of loss or lost opportunity resulting from financial management and market conditions that could have an impact on Encanas business.
Financial risks include, but are not limited to:
|
● |
|
market pricing of natural gas and liquids; |
|
● |
|
foreign exchange rates; and |
Encana partially
mitigates its exposure to financial risks through the use of various financial instruments and physical contracts. The use of derivative financial instruments is governed under formal policies and is subject to limits established by the Board. All
derivative financial agreements are with major global financial institutions or with corporate counterparties having investment grade credit ratings. Encana has in place policies and procedures with respect to the required documentation and
approvals for the use of derivative financial instruments and specifically ties their use to the mitigation of financial risk in order to support capital plans and strategic objectives.
To partially mitigate commodity price risk, the Company may enter into transactions that fix, set a floor or combine to set floors and caps on price
exposures. To help protect against regional price differentials, Encana executes transactions to manage the price differentials between its production areas and various sales points. Further information, including the details of Encanas
financial instruments as at September 30, 2015, is disclosed in Note 21 to the Interim Condensed Consolidated Financial Statements.
Counterparty credit risks are regularly and proactively managed. A substantial portion of Encanas credit exposure is with customers in the oil and
gas industry or financial institutions. Credit exposures are managed through the use of Board-approved credit policies governing the Companys credit portfolio, including credit practices that limit transactions and grant payment terms
according to industry standards and counterparties credit quality.
The Company manages liquidity risk using cash and debt management
programs. The Company has access to cash equivalents and a range of funding alternatives at competitive rates through committed revolving bank credit
|
|
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
facilities as well as debt and equity capital markets. Encana closely monitors the Companys ability to access cost-effective credit and ensures that sufficient liquidity is in place to fund
capital expenditures and dividend payments. The Company minimizes its liquidity risk by managing its capital structure which may include adjusting capital spending, adjusting dividends paid to shareholders, issuing new shares, issuing new debt or
repaying existing debt.
Operational Risks
Operational risks are defined as the risk of loss or lost opportunity resulting from the following:
|
● |
|
capital activities, including the ability to complete projects; and |
|
● |
|
reserves and resources replacement. |
The Companys ability to operate, generate cash flows, complete projects, and value reserves and resources is subject to financial risks, including
commodity price volatility mentioned above, continued market demand for its products and other factors outside of its control. These factors include: general business and market conditions; economic recessions and financial market turmoil; the
overall state of the capital markets, including investor appetite for investments in the oil and gas industry generally and the Companys securities in particular; the ability to secure and maintain cost-effective financing for its commitments;
legislative, environmental and regulatory matters; unexpected cost increases; royalties; taxes; partner funding for their share of joint venture and partnership commitments; the availability of drilling and other equipment; the ability to access
lands; the ability to access water for hydraulic fracturing operations; weather; the availability of processing capacity; the availability and proximity of take-away capacity; technology failures; the ability to integrate new assets; cyber-attacks;
accidents; the availability of skilled labour; and reservoir quality. If Encana fails to acquire or find additional natural gas and liquids reserves and resources, its reserves, resources and production will decline materially from their current
levels and, therefore, its cash flows are highly dependent upon successfully exploiting current reserves and resources and acquiring, discovering or developing additional reserves and resources. To mitigate these risks, as part of the capital
approval process, the Companys projects are evaluated on a fully risked basis, including geological risk, engineering risk and reliance on third party service providers.
When making operating and investing decisions, Encanas highly disciplined, dynamic and centrally controlled capital allocation program ensures
investment dollars are directed in a manner that is consistent with the Companys strategy. Encana also mitigates operational risks through a number of other policies, systems and processes as well as by maintaining a comprehensive insurance
program.
In June 2015, the Alberta Government convened a panel to undertake a review of the provinces oil and gas royalty structure. The
panel is currently consulting with industry, the public and stakeholders and is expected to report back to the Alberta Government by the end of 2015. Encana is monitoring the work of the panel and is actively engaged in the consultations. The
Company will assess the impact of possible changes to the royalty structure on its operations as information becomes available.
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
|
|
Environmental, Regulatory, Reputational and Safety Risks
The Company is committed to safety in its operations and has high regard for the environment and stakeholders, including the public and regulators. The
Companys business is subject to all of the operating risks normally associated with the exploration for, development of and production of natural gas, oil and NGLs and the operation of midstream facilities. When assessing the materiality of
environmental risk factors, Encana takes into account a number of qualitative and quantitative factors, including, but not limited to, the financial, operational, reputational and regulatory aspects of each identified risk factor. These risks are
managed by executing policies and standards that are designed to comply with or exceed government regulations and industry standards. In addition, Encana maintains a system that identifies, assesses and controls safety, security and environmental
risk and requires regular reporting to the Executive Leadership Team and the Board. The Corporate Responsibility, Environment, Health and Safety Committee of Encanas Board provides recommended environmental policies for approval by
Encanas Board and oversees compliance with government laws and regulations. Monitoring and reporting programs for environmental, health and safety performance in day-to-day operations, as well as inspections and audits, are designed to provide
assurance that environmental and regulatory standards are met. Emergency response plans are in place to provide guidance during times of crisis. Contingency plans are in place for a timely response to environmental events and remediation/reclamation
strategies are utilized to restore the environment.
Encanas operations are subject to regulation and intervention by governments that can
affect or prohibit the drilling, completion, including hydraulic fracturing and tie-in of wells, production, the construction or expansion of facilities and the operation and abandonment of fields. Changes in government regulation could impact the
Companys existing and planned projects as well as impose a cost of compliance.
In the state of Colorado, several cities have passed local
ordinances limiting or banning certain oil and gas activities, including hydraulic fracturing. These local rule-making initiatives have not significantly impacted the Companys operations or development plans in the state to date. Encana
continues to work with state and local governments, academics and industry leaders to respond to hydraulic fracturing related concerns in Colorado. The Company recognizes that additional hydraulic fracturing ballot and/or local rule-making limiting
or restricting oil and gas development activities are a possibility in the future and will continue to monitor and respond to these developments in 2015.
The U.S. federal government has noted climate change action as a priority for the current administration. On January 14, 2015, the Environmental
Protection Agency (EPA) outlined a series of steps to address methane and volatile organic compound emissions from the oil and gas industry, including a new goal to reduce oil and gas methane emissions by 40 to 45 percent from 2012
levels by 2025. The reductions will be achieved through regulatory and voluntary measures released on August 18, 2015 for public comment. Encana continues to monitor these developments, provide comment as appropriate and assess the potential
impact on its business. The EPA is expected to release the final rule and guidance in 2016.
On June 25, 2015 the Alberta Government announced
that it was renewing and updating the Specified Gas Emitters Regulation (the Regulation), which governs carbon emissions and was set to expire on June 30, 2015. The Regulation requires any facility that emits 100,000 tonnes or more
of greenhouse gases per year to reduce their emissions intensity. The renewed Regulation increases the reduction target from 12 percent to 20 percent by 2017 and increases the cost of carbon from C$15 per tonne to C$30 per tonne by 2017 for those
facilities that are unable to meet the specified reduction targets. Encana does not own or operate any facilities which exceed the 100,000 tonne threshold and, as a result, is not currently subject to the Regulation.
Various levels of government within Canada have enhanced focus on climate change policy during 2015. Encana continues to monitor developments and engage
in the consultations as appropriate.
A comprehensive discussion of Encanas risk management is provided in the Companys annual MD&A
for the year ended December 31, 2014.
|
|
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
Internal Control over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over the Companys financial reporting, which is a process
designed by, or designed under the supervision of the Chief Executive Officer and Chief Financial Officer, and effected by the Board, Management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance with U.S. GAAP.
Encana previously limited the scope and design and
subsequent evaluation of internal controls over financial reporting to exclude the controls, policies and procedures of Athlon Energy Inc., acquired through a business combination on November 13, 2014. During the second quarter of 2015, the
Company completed the evaluation and integration of the controls, policies and procedures of Athlon Energy Inc. and no material weaknesses or significant deficiencies were noted during the integration. There have been no changes to the
Companys internal control over financial reporting during the three months ended September 30, 2015 that have materially affected, or are reasonably likely to materially affect, the effectiveness of the internal control over financial
reporting.
Limitations of the Effectiveness of Controls
The Companys control system was designed to provide reasonable assurance to Management regarding the preparation and presentation of the
Consolidated Financial Statements. Control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement
preparation and presentation and should not be expected to prevent all errors or fraud. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in
conditions, or that the degree of compliance with the policies or procedures may deteriorate.
|
Accounting Policies and Estimates |
Critical Accounting Estimates
Refer to the annual MD&A for the year
ended December 31, 2014 for a comprehensive discussion of Encanas Critical Accounting Policies and Estimates.
Recent Accounting Pronouncements
Changes in Accounting
Policies and Practices
On January 1, 2015, Encana adopted Accounting Standard Update (ASU) 2014-08, Reporting
Discontinued Operations and Disclosures of Disposals of Components of an Entity as issued by the Financial Accounting Standards Board (FASB). The update amends the criteria and expands the disclosures for reporting discontinued
operations. Under the new criteria, only disposals representing a strategic shift in operations would qualify as a discontinued operation. The amendments have been applied prospectively and have not had a material impact on the Companys
Interim Condensed Consolidated Financial Statements.
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
|
|
New Standards Issued Not Yet Adopted
As of January 1, 2016, Encana will be required to adopt the following pronouncements issued by the FASB:
|
● |
|
ASU 2014-12, Compensation Stock Compensation: Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance
Target Could Be Achieved After the Requisite Service Period. The update requires that a performance target that affects vesting and could be achieved after the requisite service period be treated as a performance condition. The amendments will
be applied prospectively and are not expected to have a material impact on the Companys Consolidated Financial Statements. |
|
● |
|
ASU 2015-02, Amendments to the Consolidation Analysis. The update requires limited partnerships and similar entities to be evaluated under the
variable interest and voting interest models, eliminate the presumption that a general partner should consolidate a limited partnership, and simplify the identification of variable interests and related effect on the primary beneficiary criterion
when fees are paid to a decision maker. The amendments can be applied using either a full retrospective approach or a modified retrospective approach at the date of adoption. Encana is currently assessing the potential impact of the amendments on
the Companys Consolidated Financial Statements. |
|
● |
|
ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs. The update requires debt issuance costs to be presented on the balance sheet as a
deduction from the carrying amount of the related liability. Previously, debt issuance costs were presented as a deferred charge within assets. In August 2015, the FASB issued ASU 2015-15, Presentation and Subsequent Measurement of Debt Issuance
Costs Associated with Line-of-Credit Arrangements. The update further clarifies that regardless of whether there are outstanding borrowings, debt issuance costs arising from credit arrangements can be presented as an asset and subsequently
amortized ratably over the term of the arrangement. These amendments will be applied retrospectively. As at September 30, 2015, $31 million of debt issuance costs were presented in Other Assets on the Companys Interim Condensed
Consolidated Balance Sheet ($39 million as at December 31, 2014). |
As of January 1, 2018, Encana will be required to
adopt ASU 2014-09, Revenue from Contracts with Customers under Topic 606, which was the result of a joint project by the FASB and International Accounting Standards Board. The new standard replaces Topic 605, Revenue Recognition, and
other industry-specific guidance in the Accounting Standards Codification. The new standard is based on the principle that revenue is recognized on the transfer of promised goods or services to customers in an amount that reflects the consideration
the Company expects to be entitled to in exchange for those goods or services. In August 2015, the FASB issued ASU 2015-14, Deferral of Effective Date for Revenue from Contracts with Customers, which deferred the effective date of ASU
2014-09, but permits early adoption using the original effective date of January 1, 2017. The standard can be applied using one of two retrospective application methods at the date of adoption. Encana is currently assessing the potential impact
of the standard on the Companys Consolidated Financial Statements.
|
|
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
Certain measures in this document do not have any standardized meaning as prescribed by U.S. GAAP and, therefore, are
considered non-GAAP measures. These measures may not be comparable to similar measures presented by other issuers. 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 Companys liquidity and its ability to generate funds to finance its operations. Non-GAAP measures include: Cash Flow; Free Cash Flow; Operating Earnings (Loss); Upstream Operating Cash Flow, excluding
Hedging; Operating Netback; Debt to Debt Adjusted Cash Flow; and Debt to Adjusted Capitalization. Managements use of these measures is discussed further below.
Cash Flow and Free Cash Flow
Cash Flow is a non-GAAP measure commonly used in the oil and gas industry and by Encana to assist Management and investors in measuring the
Companys ability to finance capital programs and meet financial obligations. Cash Flow is defined as cash from operating activities excluding net change in other assets and liabilities, net change in non-cash working capital and cash tax on
sale of assets.
Free Cash Flow is a non-GAAP measure defined as Cash Flow in excess of capital investment, excluding net acquisitions and
divestitures, and is used to determine the funds available for other investing and/or financing activities.
|
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|
|
Nine months
ended September 30 |
|
|
|
|
2015 |
|
|
|
|
2014 |
|
|
|
|
2013 |
|
($ millions) |
|
2015 |
|
|
2014 |
|
|
|
|
Q3 |
|
|
Q2 |
|
|
Q1 |
|
|
|
|
Q4 |
|
|
Q3 |
|
|
Q2 |
|
|
Q1 |
|
|
|
|
Q4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash From (Used in) Operating Activities |
|
$ |
1,233 |
|
|
$ |
2,406 |
|
|
|
|
$ |
453 |
|
|
$ |
298 |
|
|
$ |
482 |
|
|
|
|
$ |
261 |
|
|
$ |
696 |
|
|
$ |
767 |
|
|
$ |
943 |
|
|
|
|
$ |
462 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Add back) deduct: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net change in other assets and liabilities |
|
|
(18 |
) |
|
|
(28 |
) |
|
|
|
|
(18 |
) |
|
|
7 |
|
|
|
(7 |
) |
|
|
|
|
(15 |
) |
|
|
(11 |
) |
|
|
(8 |
) |
|
|
(9 |
) |
|
|
|
|
(21 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net change in non-cash working capital |
|
|
204 |
|
|
|
132 |
|
|
|
|
|
100 |
|
|
|
110 |
|
|
|
(6 |
) |
|
|
|
|
(141 |
) |
|
|
155 |
|
|
|
119 |
|
|
|
(142 |
) |
|
|
|
|
(183 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash tax on sale of assets |
|
|
- |
|
|
|
(255 |
) |
|
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
|
|
40 |
|
|
|
(255 |
) |
|
|
- |
|
|
|
- |
|
|
|
|
|
(11 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flow |
|
$ |
1,047 |
|
|
$ |
2,557 |
|
|
|
|
$ |
371 |
|
|
$ |
181 |
|
|
$ |
495 |
|
|
|
|
$ |
377 |
|
|
$ |
807 |
|
|
$ |
656 |
|
|
$ |
1,094 |
|
|
|
|
$ |
677 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deduct: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital investment |
|
|
1,952 |
|
|
|
1,669 |
|
|
|
|
|
473 |
|
|
|
743 |
|
|
|
736 |
|
|
|
|
|
857 |
|
|
|
598 |
|
|
|
560 |
|
|
|
511 |
|
|
|
|
|
717 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Free Cash Flow |
|
$ |
(905 |
) |
|
$ |
888 |
|
|
|
|
$ |
(102 |
) |
|
$ |
(562 |
) |
|
$ |
(241 |
) |
|
|
|
$ |
(480 |
) |
|
$ |
209 |
|
|
$ |
96 |
|
|
$ |
583 |
|
|
|
|
$ |
(40 |
) |
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
|
|
Operating Earnings
Operating Earnings (Loss) is a non-GAAP
measure that adjusts Net Earnings (Loss) Attributable to Common Shareholders by non-operating items that Management believes reduces the comparability of the Companys underlying financial performance between periods. Operating Earnings (Loss)
is commonly used in the oil and gas industry and by Encana to provide investors with information that is more comparable between periods.
Operating
Earnings (Loss) is defined as Net Earnings (Loss) Attributable to Common Shareholders excluding non-recurring or non-cash items that Management believes reduces the comparability of the Companys financial performance between periods. These
after-tax items may include, but are not limited to, unrealized hedging gains/losses, impairments, restructuring charges, non-operating foreign exchange gains/losses, gains/losses on divestitures, income taxes related to divestitures and adjustments
to normalize the effect of income taxes calculated using the estimated annual effective income tax rate.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine months ended September 30 |
|
|
|
|
2015 |
|
|
|
|
2014 |
|
|
|
|
2013 |
|
($ millions) |
|
2015 |
|
|
2014 |
|
|
|
|
Q3 |
|
|
Q2 |
|
|
Q1 |
|
|
|
|
Q4 |
|
|
Q3 |
|
|
Q2 |
|
|
Q1 |
|
|
|
|
Q4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Earnings (Loss) Attributable to Common Shareholders |
|
$ |
(4,553 |
) |
|
$ |
3,194 |
|
|
|
|
$ |
(1,236 |
) |
|
$ |
(1,610 |
) |
|
$ |
(1,707 |
) |
|
|
|
$ |
198 |
|
|
$ |
2,807 |
|
|
$ |
271 |
|
|
$ |
116 |
|
|
|
|
$ |
(251 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
After-tax (addition) / deduction: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized hedging gain (loss) |
|
|
(178 |
) |
|
|
(35 |
) |
|
|
|
|
107 |
|
|
|
(187 |
) |
|
|
(98 |
) |
|
|
|
|
341 |
|
|
|
160 |
|
|
|
8 |
|
|
|
(203 |
) |
|
|
|
|
(209 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Impairments |
|
|
(3,616 |
) |
|
|
- |
|
|
|
|
|
(1,066 |
) |
|
|
(1,328 |
) |
|
|
(1,222 |
) |
|
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restructuring charges (1) |
|
|
(40 |
) |
|
|
(20 |
) |
|
|
|
|
(20 |
) |
|
|
(10 |
) |
|
|
(10 |
) |
|
|
|
|
(4 |
) |
|
|
(5 |
) |
|
|
(5 |
) |
|
|
(10 |
) |
|
|
|
|
(64 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-operating foreign exchange gain (loss) |
|
|
(606 |
) |
|
|
(256 |
) |
|
|
|
|
(212 |
) |
|
|
114 |
|
|
|
(508 |
) |
|
|
|
|
(151 |
) |
|
|
(218 |
) |
|
|
156 |
|
|
|
(194 |
) |
|
|
|
|
(124 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain (loss) on divestitures |
|
|
9 |
|
|
|
2,534 |
|
|
|
|
|
(2 |
) |
|
|
1 |
|
|
|
10 |
|
|
|
|
|
(11 |
) |
|
|
2,399 |
|
|
|
135 |
|
|
|
- |
|
|
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax adjustments |
|
|
50 |
|
|
|
4 |
|
|
|
|
|
(19 |
) |
|
|
(33 |
) |
|
|
102 |
|
|
|
|
|
(12 |
) |
|
|
190 |
|
|
|
(194 |
) |
|
|
8 |
|
|
|
|
|
(80 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Earnings (Loss) (1) |
|
$ |
(172 |
) |
|
$ |
967 |
|
|
|
|
$ |
(24 |
) |
|
$ |
(167 |
) |
|
$ |
19 |
|
|
|
|
$ |
35 |
|
|
$ |
281 |
|
|
$ |
171 |
|
|
$ |
515 |
|
|
|
|
$ |
226 |
|
|
(1) |
In continued support of Encanas strategy, organizational structure changes were formalized in Q2 2015 and resulted in a revision to the Q1 2015
Operating Earnings to exclude restructuring charges incurred in the first quarter. |
|
|
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
Upstream Operating Cash Flow, excluding Hedging
Upstream Operating Cash Flow, excluding
Hedging is a non-GAAP measure that adjusts the Canadian and USA Operations revenues, net of royalties for production and mineral taxes, transportation and processing expense, operating expense and the impacts of realized hedging. Management monitors
Upstream Operating Cash Flow, excluding Hedging as it reflects operating performance and measures the Companys portfolio transition to higher margin production. Upstream Operating Cash Flow, excluding Hedging is reconciled to GAAP measures in
the Results of Operations section of this MD&A. The table below totals Upstream Operating Cash Flow for Encana.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine months ended September 30 |
|
|
|
|
2015 |
|
|
|
|
2014 |
|
|
|
|
2013 |
|
($ millions) |
|
2015 |
|
|
2014 |
|
|
|
|
Q3 |
|
|
Q2 |
|
|
Q1 |
|
|
|
|
Q4 |
|
|
Q3 |
|
|
Q2 |
|
|
Q1 |
|
|
|
|
Q4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Upstream Operating Cash Flow |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
$ |
784 |
|
|
$ |
1,805 |
|
|
|
|
$ |
200 |
|
|
$ |
171 |
|
|
$ |
413 |
|
|
|
|
$ |
341 |
|
|
$ |
477 |
|
|
$ |
447 |
|
|
$ |
881 |
|
|
|
|
$ |
526 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
USA Operations |
|
|
928 |
|
|
|
1,292 |
|
|
|
|
|
331 |
|
|
|
308 |
|
|
|
289 |
|
|
|
|
|
480 |
|
|
|
505 |
|
|
|
353 |
|
|
|
434 |
|
|
|
|
|
375 |
|
|
|
$ |
1,712 |
|
|
$ |
3,097 |
|
|
|
|
$ |
531 |
|
|
$ |
479 |
|
|
$ |
702 |
|
|
|
|
$ |
821 |
|
|
$ |
982 |
|
|
$ |
800 |
|
|
$ |
1,315 |
|
|
|
|
$ |
901 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Add back) deduct: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized Hedging Gain (Loss) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
$ |
366 |
|
|
$ |
(105 |
) |
|
|
|
$ |
109 |
|
|
$ |
101 |
|
|
$ |
156 |
|
|
|
|
$ |
49 |
|
|
$ |
19 |
|
|
$ |
(49 |
) |
|
$ |
(75 |
) |
|
|
|
$ |
90 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
USA Operations |
|
|
263 |
|
|
|
(103 |
) |
|
|
|
|
108 |
|
|
|
63 |
|
|
|
92 |
|
|
|
|
|
78 |
|
|
|
11 |
|
|
|
(49 |
) |
|
|
(65 |
) |
|
|
|
|
83 |
|
|
|
$ |
629 |
|
|
$ |
(208 |
) |
|
|
|
$ |
217 |
|
|
$ |
164 |
|
|
$ |
248 |
|
|
|
|
$ |
127 |
|
|
$ |
30 |
|
|
$ |
(98 |
) |
|
$ |
(140 |
) |
|
|
|
$ |
173 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Upstream Operating Cash Flow, excluding Hedging |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
$ |
418 |
|
|
$ |
1,910 |
|
|
|
|
$ |
91 |
|
|
$ |
70 |
|
|
$ |
257 |
|
|
|
|
$ |
292 |
|
|
$ |
458 |
|
|
$ |
496 |
|
|
$ |
956 |
|
|
|
|
$ |
436 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
USA Operations |
|
|
665 |
|
|
|
1,395 |
|
|
|
|
|
223 |
|
|
|
245 |
|
|
|
197 |
|
|
|
|
|
402 |
|
|
|
494 |
|
|
|
402 |
|
|
|
499 |
|
|
|
|
|
292 |
|
|
|
$ |
1,083 |
|
|
$ |
3,305 |
|
|
|
|
$ |
314 |
|
|
$ |
315 |
|
|
$ |
454 |
|
|
|
|
$ |
694 |
|
|
$ |
952 |
|
|
$ |
898 |
|
|
$ |
1,455 |
|
|
|
|
$ |
728 |
|
Operating Netback
Operating Netback is a common metric used in
the oil and gas industry to measure operating performance by product. Operating Netbacks are calculated by determining product revenues, net of royalties and deducting costs associated with delivering the product to market, including production and
mineral taxes, transportation and processing expense and operating expense. The Operating Netback calculation is shown in the Results of Operations section of this MD&A.
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
|
|
Debt to Debt Adjusted Cash Flow
Debt to Debt Adjusted Cash Flow is a
non-GAAP measure monitored by Management as an indicator of the Companys overall financial strength. Debt Adjusted Cash Flow is a non-GAAP measure defined as Cash Flow on a trailing 12-month basis excluding interest expense after tax.
|
|
|
|
|
|
|
|
|
($ millions) |
|
September 30, 2015 |
|
|
December 31, 2014 |
|
|
|
|
Debt |
|
$ |
6,128 |
|
|
$ |
7,340 |
|
|
|
|
Cash Flow |
|
|
1,424 |
|
|
|
2,934 |
|
|
|
|
Interest Expense, after tax |
|
|
561 |
|
|
|
486 |
|
Debt Adjusted Cash Flow |
|
$ |
1,985 |
|
|
$ |
3,420 |
|
Debt to Debt Adjusted Cash Flow |
|
|
3.1x |
|
|
|
2.1x |
|
Debt to Adjusted Capitalization
Debt to Adjusted Capitalization is a
non-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 Encanas financial covenant under its
credit facility agreements 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 Companys January 1, 2012 adoption of U.S. GAAP.
|
|
|
|
|
|
|
|
|
($ millions) |
|
September 30, 2015 |
|
|
December 31, 2014 |
|
|
|
|
Debt |
|
$ |
6,128 |
|
|
$ |
7,340 |
|
|
|
|
Total Shareholders Equity |
|
|
6,719 |
|
|
|
9,685 |
|
|
|
|
Equity Adjustment for Impairments at December 31, 2011 |
|
|
7,746 |
|
|
|
7,746 |
|
Adjusted Capitalization |
|
$ |
20,593 |
|
|
$ |
24,771 |
|
Debt to Adjusted Capitalization |
|
|
30% |
|
|
|
30% |
|
|
|
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
Forward-Looking Statements
This document contains certain
forward-looking statements or information (collectively, forward-looking statements) within the meaning of applicable securities legislation. Forward-looking statements include, but are not limited to:
|
● |
|
anticipated cash and cash equivalents |
|
● |
|
the expected proceeds from the Haynesville and DJ Basin transactions, the value to Encana and the use of proceeds therefrom, the timing of the closings and
the expectation that closing conditions will be satisfied |
|
● |
|
the anticipated benefits to Encana of entering into ancillary gathering, midstream and marketing arrangements with GeoSouthern |
|
● |
|
the projections and expectation of meeting the targets contained in the Companys 2015 corporate guidance |
|
● |
|
anticipated oil, natural gas and NGLs prices |
|
● |
|
expected future interest expense savings |
|
● |
|
anticipated future cost and operating efficiencies |
|
● |
|
the Companys expectation to fund its 2015 commitments and obligations from Cash Flow and cash and cash equivalents |
|
● |
|
managing risk, including the possible impact of changes to the royalty structure |
|
● |
|
flexibility of capital spending plans |
|
● |
|
estimates of reserves and resources
|
|
● |
|
financial flexibility and discipline, access to cash and cash equivalents and other methods of funding, the ability to meet financial obligations, manage
debt and financial ratios, finance growth and compliance with financial covenants |
|
● |
|
statements with respect to future ceiling test impairments |
|
● |
|
the continued evolution of the Companys resource play hub model to drive greater productivity and cost efficiencies |
|
● |
|
anticipated revenues and operating expenses |
|
● |
|
statements with respect to its strategic objectives |
|
● |
|
the adequacy of the Companys provision for taxes and legal claims |
|
● |
|
the possible impact of environmental legislation and/or regulations |
|
● |
|
anticipated proceeds and future benefits from various joint venture, partnership and other agreements |
|
● |
|
the possible impact and timing of accounting pronouncements, rule changes and standards
|
Readers are cautioned upon unduly
relying on forward-looking statements as there can be no assurance that the plans, intentions or expectations upon which they are based will occur. By their nature, these statements involve numerous assumptions, known and unknown risks and
uncertainties and other factors, which can contribute to the possibility that such statements will not occur or which may cause the actual performance and financial results of the Company to differ materially from those expressed or implied by such
statements. These assumptions include, but are not limited to:
|
● |
|
achieving average production for 2015 of between 1.60 Bcf/d and 1.70 Bcf/d of natural gas and 130 Mbbls/d to 150 Mbbls/d of liquids |
|
● |
|
commodity prices for natural gas and liquids based on NYMEX of $3.00 per MMBtu, AECO of C$2.62 per GJ and WTI of $50 per bbl through the remainder of 2015
|
|
● |
|
U.S./Canadian dollar exchange rate of 0.80 |
|
● |
|
a weighted average number of outstanding shares of approximately 821 million |
|
● |
|
availability of attractive hedge contracts |
|
● |
|
effectiveness of the Companys resource play hub model to drive productivity and efficiencies
|
|
● |
|
results from innovations |
|
● |
|
the expectation that GeoSouthern will successfully fulfill its obligations under the ancillary gathering, midstream and marketing agreements
|
|
● |
|
the ability to satisfy closing conditions, the successful closing of, and the value of post-closing and other adjustments associated with the Haynesville and
DJ Basin assets |
|
● |
|
expectations and projections made in light of, and generally consistent with, Encanas historical experience and its perception of historical trends,
including with respect to the pace of technological development, the benefits achieved and general industry expectations
|
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
|
|
Risks and uncertainties that may affect the operations and development of our business include, but are not
limited to: the ability to generate sufficient cash flow to meet the Companys obligations; risks inherent to closing announced divestitures and adjustments that may reduce the expected proceeds and value to Encana; commodity price volatility;
ability to secure adequate product transportation and potential pipeline curtailments; variability of dividends to be paid; the timing and costs of well, facilities and pipeline construction; business interruption and casualty losses or unexpected
technical difficulties; counterparty and credit risk; risk and effect of a downgrade in credit rating, including access to capital markets; fluctuations in currency and interest rates; assumptions based upon the Companys 2015 corporate
guidance; failure to achieve anticipated results from cost and efficiency initiatives; risks inherent in marketing operations; risks associated with technology; the Companys ability to acquire or find additional reserves; imprecision of
reserves estimates and estimates of recoverable quantities of natural gas and liquids from resource plays and other sources not currently classified as proved, probable or possible reserves or economic contingent resources, including future net
revenue estimates; risks associated with past and future divestitures of certain assets or other transactions or receive amounts contemplated under the transaction agreements (such transactions may include third-party capital investments, farm-outs
or partnerships, which Encana may refer to from time to time as partnerships or joint ventures and the funds received in respect thereof which Encana may refer to from time to time as proceeds, deferred
purchase price and/or carry capital, regardless of the legal form) as a result of various conditions not being met; and other risks and uncertainties impacting Encanas business as described from time to time in Encanas
annual MD&A, financial statements, Annual Information Form and Form 40-F, as filed on SEDAR and EDGAR.
Although Encana believes that the
expectations represented by such forward-looking statements are reasonable, there can be no assurance that such expectations will prove to be correct. Readers are cautioned that the assumptions, risks and uncertainties referenced above are not
exhaustive. The forward-looking statements contained in this document are made as of the date of this document and, except as required by law, Encana undertakes no obligation to update publicly or revise any forward-looking statements. The
forward-looking statements contained in this document are expressly qualified by these cautionary statements.
Encana is required to disclose events
and circumstances that occurred during the period to which this MD&A relates that are reasonably likely to cause actual results to differ materially from material forward-looking statements for a period that is not yet complete that Encana has
previously disclosed to the public and the expected differences thereto. Such disclosure can be found in Encanas news release dated November 12, 2015, which is available on Encanas website at www.encana.com, on SEDAR at www.sedar.com and EDGAR at
www.sec.gov.
|
|
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
Oil and Gas Information
National Instrument 51-101 (NI
51-101) of the Canadian Securities Administrators imposes oil and gas disclosure standards for Canadian public companies engaged in oil and gas activities. The Canadian protocol disclosure is contained in Appendix A and under Narrative
Description of the Business in the Companys Annual Information Form (AIF). Encana obtained an exemption dated January 4, 2011 from certain requirements of NI 51-101 to permit it to provide certain disclosure prepared in
accordance with U.S. disclosure requirements, in addition to the Canadian protocol disclosure. The Companys U.S. protocol disclosure is included in Note 26 (unaudited) to the Companys Consolidated Financial Statements for the year ended
December 31, 2014 and in Appendix D of the AIF.
Further, Encana obtained an exemption dated January 21, 2015 from certain
requirements of NI 51-101 to permit it to use the definition of product type contained in the amendments to NI 51-101, published by the securities regulatory authority in each of the jurisdictions of Canada on December 4, 2014 that
came into force on July 1, 2015, as it relates to its Canadian protocol disclosure contained in Appendix A of the AIF.
A description of the
primary differences between the disclosure requirements under the Canadian standards and under the U.S. standards is set forth under the heading Reserves and Other Oil and Gas Information in the AIF.
Natural Gas, Oil and NGLs Conversions
The conversion of natural gas volumes to 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.
Play and Resource Play
Play is
a term used by Encana which encompasses resource plays, geological formations and conventional plays. Resource play is a term used by Encana to describe an accumulation of hydrocarbons known to exist over a large areal expanse and/or thick vertical
section, which, when compared to a conventional play, typically has a lower geological and/or commercial development risk and lower average decline rate.
Additional Information
Further information regarding Encana Corporation, including its AIF, can be accessed under the Companys public filings found on SEDAR at www.sedar.com, on EDGAR at www.sec.gov and on the Companys
website at www.encana.com.
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
|
|
|
|
|
|
|
|
Encana Corporation
Interim Condensed Consolidated Financial Statements
(unaudited)
For the period ended September 30, 2015
(U.S. Dollars)
|
Third quarter report
for the period ended September 30, 2015
Condensed
Consolidated Statement of Earnings (unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
September 30, |
|
|
Nine Months Ended
September 30, |
|
($ millions, except per share amounts) |
|
|
|
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
|
Revenues, Net of Royalties |
|
|
(Note 3) |
|
|
$ |
1,312 |
|
|
$ |
2,285 |
|
|
$ |
3,391 |
|
|
$ |
5,765 |
|
|
|
|
|
|
|
Expenses |
|
|
(Note 3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and mineral taxes |
|
|
|
|
|
|
27 |
|
|
|
17 |
|
|
|
72 |
|
|
|
97 |
|
|
|
|
|
|
|
Transportation and processing |
|
|
|
|
|
|
319 |
|
|
|
370 |
|
|
|
959 |
|
|
|
1,149 |
|
|
|
|
|
|
|
Operating |
|
|
|
|
|
|
190 |
|
|
|
190 |
|
|
|
588 |
|
|
|
557 |
|
|
|
|
|
|
|
Purchased product |
|
|
|
|
|
|
60 |
|
|
|
474 |
|
|
|
260 |
|
|
|
844 |
|
|
|
|
|
|
|
Depreciation, depletion and amortization |
|
|
|
|
|
|
352 |
|
|
|
476 |
|
|
|
1,212 |
|
|
|
1,294 |
|
|
|
|
|
|
|
Impairments |
|
|
(Note 9) |
|
|
|
1,671 |
|
|
|
- |
|
|
|
5,668 |
|
|
|
- |
|
|
|
|
|
|
|
Accretion of asset retirement obligation |
|
|
(Note 12) |
|
|
|
11 |
|
|
|
13 |
|
|
|
34 |
|
|
|
39 |
|
|
|
|
|
|
|
Administrative |
|
|
(Note 17) |
|
|
|
61 |
|
|
|
69 |
|
|
|
217 |
|
|
|
269 |
|
|
|
|
|
|
|
Interest |
|
|
(Note 6) |
|
|
|
105 |
|
|
|
133 |
|
|
|
508 |
|
|
|
402 |
|
|
|
|
|
|
|
Foreign exchange (gain) loss, net |
|
|
(Note 7) |
|
|
|
348 |
|
|
|
202 |
|
|
|
918 |
|
|
|
254 |
|
|
|
|
|
|
|
(Gain) loss on divestitures |
|
|
(Notes 5, 15) |
|
|
|
2 |
|
|
|
(3,239) |
|
|
|
(14) |
|
|
|
(3,442) |
|
|
|
|
|
|
|
Other |
|
|
|
|
|
|
(3) |
|
|
|
- |
|
|
|
2 |
|
|
|
8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,143 |
|
|
|
(1,295) |
|
|
|
10,424 |
|
|
|
1,471 |
|
|
|
|
|
|
|
Net Earnings (Loss) Before Income Tax |
|
|
|
|
|
|
(1,831) |
|
|
|
3,580 |
|
|
|
(7,033) |
|
|
|
4,294 |
|
|
|
|
|
|
|
Income tax expense (recovery) |
|
|
(Note 8) |
|
|
|
(595) |
|
|
|
749 |
|
|
|
(2,480) |
|
|
|
1,066 |
|
|
|
|
|
|
|
Net Earnings (Loss) |
|
|
|
|
|
|
(1,236) |
|
|
|
2,831 |
|
|
|
(4,553) |
|
|
|
3,228 |
|
|
|
|
|
|
|
Net earnings attributable to noncontrolling interest |
|
|
(Note 15) |
|
|
|
- |
|
|
|
(24) |
|
|
|
- |
|
|
|
(34) |
|
|
|
|
|
|
|
Net Earnings (Loss) Attributable to Common Shareholders |
|
|
|
|
|
$ |
(1,236) |
|
|
$ |
2,807 |
|
|
$ |
(4,553) |
|
|
$ |
3,194 |
|
|
|
|
|
|
|
Net Earnings (Loss) per Common Share |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic & Diluted |
|
|
(Note 13) |
|
|
$ |
(1.47) |
|
|
$ |
3.79 |
|
|
$ |
(5.59) |
|
|
$ |
4.31 |
|
Condensed
Consolidated Statement of Comprehensive Income (unaudited) |
|
|
|
|
|
|
|
|
Three Months Ended
September 30, |
|
|
Nine Months Ended
September 30, |
|
($ millions) |
|
|
|
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
|
Net Earnings (Loss) |
|
|
|
|
|
$ |
(1,236) |
|
|
$ |
2,831 |
|
|
$ |
(4,553) |
|
|
$ |
3,228 |
|
|
|
|
|
|
|
Other Comprehensive Income (Loss), Net of Tax |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign currency translation adjustment |
|
|
(Note 14) |
|
|
|
175 |
|
|
|
(58) |
|
|
|
600 |
|
|
|
(36) |
|
|
|
|
|
|
|
Pension and other post-employment benefit plans |
|
|
(Notes 14,19) |
|
|
|
1 |
|
|
|
- |
|
|
|
2 |
|
|
|
- |
|
|
|
|
|
|
|
Other Comprehensive Income (Loss) |
|
|
|
|
|
|
176 |
|
|
|
(58) |
|
|
|
602 |
|
|
|
(36) |
|
|
|
|
|
|
|
Comprehensive Income (Loss) |
|
|
|
|
|
|
(1,060) |
|
|
|
2,773 |
|
|
|
(3,951) |
|
|
|
3,192 |
|
|
|
|
|
|
|
Comprehensive Income Attributable to Noncontrolling Interest |
|
|
(Note 15) |
|
|
|
- |
|
|
|
(24) |
|
|
|
- |
|
|
|
(34) |
|
Comprehensive Income (Loss) Attributable to Common Shareholders |
|
|
$ |
(1,060) |
|
|
$ |
2,749 |
|
|
$ |
(3,951) |
|
|
$ |
3,158 |
|
See accompanying Notes to Condensed Consolidated Financial Statements
|
|
|
Condensed Consolidated Financial Statements
Prepared in accordance with U.S. GAAP in US$ |
|
|
Third quarter report
for the period ended September 30, 2015
Condensed
Consolidated Balance Sheet (unaudited)
|
|
|
|
|
|
|
|
|
|
|
($ millions) |
|
|
|
As at September 30, 2015 |
|
|
As at December 31, 2014 |
|
|
|
|
|
Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
|
|
$ |
352 |
|
|
$ |
338 |
|
|
|
|
|
Accounts receivable and accrued revenues |
|
|
|
|
705 |
|
|
|
1,307 |
|
|
|
|
|
Risk management |
|
(Note 21) |
|
|
427 |
|
|
|
707 |
|
|
|
|
|
Income tax receivable |
|
|
|
|
353 |
|
|
|
509 |
|
|
|
|
|
Deferred income taxes |
|
|
|
|
34 |
|
|
|
- |
|
|
|
|
|
|
1,871 |
|
|
|
2,861 |
|
|
|
|
|
Property, Plant and Equipment, at cost: |
|
(Note 9) |
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas and oil properties, based on full cost accounting |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved properties |
|
|
|
|
41,453 |
|
|
|
42,615 |
|
|
|
|
|
Unproved properties |
|
|
|
|
5,734 |
|
|
|
6,133 |
|
|
|
|
|
Other |
|
|
|
|
2,292 |
|
|
|
2,711 |
|
Property, plant and equipment |
|
|
|
|
49,479 |
|
|
|
51,459 |
|
|
|
|
|
Less: Accumulated depreciation, depletion and amortization |
|
|
|
|
(37,997) |
|
|
|
(33,444) |
|
Property, plant and equipment,
net |
|
(Note 3) |
|
|
11,482 |
|
|
|
18,015 |
|
|
|
|
|
Cash in Reserve |
|
|
|
|
1 |
|
|
|
73 |
|
|
|
|
|
Other Assets |
|
|
|
|
310 |
|
|
|
394 |
|
|
|
|
|
Risk Management |
|
(Note 21) |
|
|
51 |
|
|
|
65 |
|
|
|
|
|
Deferred Income Taxes |
|
|
|
|
767 |
|
|
|
296 |
|
|
|
|
|
Goodwill |
|
(Notes 3, 4, 5, 15) |
|
|
2,812 |
|
|
|
2,917 |
|
|
|
(Note
3) |
|
$ |
17,294 |
|
|
$ |
24,621 |
|
|
|
|
|
Liabilities and Shareholders Equity |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable and accrued liabilities |
|
|
|
$ |
1,535 |
|
|
$ |
2,243 |
|
|
|
|
|
Income tax payable |
|
|
|
|
4 |
|
|
|
15 |
|
|
|
|
|
Risk management |
|
(Note 21) |
|
|
10 |
|
|
|
20 |
|
|
|
|
|
Deferred income taxes |
|
|
|
|
45 |
|
|
|
128 |
|
|
|
|
|
|
1,594 |
|
|
|
2,406 |
|
|
|
|
|
Long-Term Debt |
|
(Note 10) |
|
|
6,128 |
|
|
|
7,340 |
|
|
|
|
|
Other Liabilities and Provisions |
|
(Note 11) |
|
|
2,067 |
|
|
|
2,484 |
|
|
|
|
|
Risk Management |
|
(Note 21) |
|
|
9 |
|
|
|
7 |
|
|
|
|
|
Asset Retirement Obligation |
|
(Note 12) |
|
|
757 |
|
|
|
870 |
|
|
|
|
|
Deferred Income Taxes |
|
|
|
|
20 |
|
|
|
1,829 |
|
|
|
|
|
|
10,575 |
|
|
|
14,936 |
|
Commitments and Contingencies |
|
(Note 22) |
|
|
|
|
|
|
|
|
|
|
|
|
Shareholders Equity |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Share capital - authorized unlimited common shares, without par value
2015 issued and outstanding:
845.7 million shares (2014: 741.2 million shares) |
|
(Note 13) |
|
|
3,601 |
|
|
|
2,450 |
|
|
|
|
|
Paid in surplus |
|
(Note 15) |
|
|
1,358 |
|
|
|
1,358 |
|
|
|
|
|
Retained earnings |
|
|
|
|
469 |
|
|
|
5,188 |
|
|
|
|
|
Accumulated other comprehensive income |
|
(Note 14) |
|
|
1,291 |
|
|
|
689 |
|
Total Shareholders Equity |
|
|
|
|
6,719 |
|
|
|
9,685 |
|
|
|
|
|
$ |
17,294 |
|
|
$ |
24,621 |
|
See accompanying Notes to Condensed Consolidated Financial Statements
|
|
|
|
|
Condensed Consolidated Financial Statements
Prepared in accordance with U.S. GAAP in US$ |
Third quarter report
for the period ended September 30, 2015
Condensed
Consolidated Statement of Changes in Shareholders Equity (unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, 2015 ($ millions) |
|
Share
Capital |
|
|
Paid in
Surplus |
|
|
Retained
Earnings |
|
|
Accumulated
Other
Comprehensive
Income |
|
|
Non-
Controlling
Interest |
|
|
Total
Shareholders
Equity |
|
|
|
|
|
|
|
|
|
Balance, December 31, 2014 |
|
|
|
$ |
2,450 |
|
|
$ |
1,358 |
|
|
$ |
5,188 |
|
|
$ |
689 |
|
|
$ |
- |
|
|
$ |
9,685 |
|
|
|
|
|
|
|
|
|
Net Earnings (Loss) |
|
|
|
|
- |
|
|
|
- |
|
|
|
(4,553) |
|
|
|
- |
|
|
|
- |
|
|
|
(4,553) |
|
|
|
|
|
|
|
|
|
Dividends on Common Shares |
|
(Note 13) |
|
|
- |
|
|
|
- |
|
|
|
(166) |
|
|
|
- |
|
|
|
- |
|
|
|
(166) |
|
|
|
|
|
|
|
|
|
Common Shares Issued |
|
(Note 13) |
|
|
1,098 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
1,098 |
|
|
|
|
|
|
|
|
|
Common Shares Issued Under Dividend Reinvestment Plan |
|
(Note 13) |
|
|
53 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
53 |
|
|
|
|
|
|
|
|
|
Other Comprehensive Income |
|
(Note 14) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
602 |
|
|
|
- |
|
|
|
602 |
|
Balance, September 30, 2015 |
|
|
|
$ |
3,601 |
|
|
$ |
1,358 |
|
|
$ |
469 |
|
|
$ |
1,291 |
|
|
$ |
- |
|
|
$ |
6,719 |
|
Nine Months Ended September 30, 2014 ($ millions) |
|
Share
Capital |
|
|
Paid in
Surplus |
|
|
Retained
Earnings |
|
|
Accumulated
Other
Comprehensive
Income |
|
|
Non-
Controlling
Interest |
|
|
Total
Shareholders
Equity |
|
|
|
|
|
|
|
|
|
Balance, December 31, 2013 |
|
|
|
$ |
2,445 |
|
|
$ |
15 |
|
|
$ |
2,003 |
|
|
$ |
684 |
|
|
$ |
- |
|
|
$ |
5,147 |
|
|
|
|
|
|
|
|
|
Share-Based Compensation |
|
(Note 18) |
|
|
- |
|
|
|
(1) |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(1) |
|
|
|
|
|
|
|
|
|
Net Earnings |
|
|
|
|
- |
|
|
|
- |
|
|
|
3,194 |
|
|
|
- |
|
|
|
34 |
|
|
|
3,228 |
|
|
|
|
|
|
|
|
|
Dividends on Common Shares |
|
(Note 13) |
|
|
- |
|
|
|
- |
|
|
|
(156) |
|
|
|
- |
|
|
|
- |
|
|
|
(156) |
|
|
|
|
|
|
|
|
|
Common Shares Issued Under Dividend Reinvestment Plan |
|
(Note 13) |
|
|
4 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
4 |
|
|
|
|
|
|
|
|
|
Other Comprehensive Income (Loss) |
|
(Note 14) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(36) |
|
|
|
- |
|
|
|
(36) |
|
|
|
|
|
|
|
|
|
Sale of Noncontrolling Interest |
|
(Note 15) |
|
|
- |
|
|
|
1,346 |
|
|
|
- |
|
|
|
- |
|
|
|
117 |
|
|
|
1,463 |
|
|
|
|
|
|
|
|
|
Distributions to Noncontrolling Interest Owners |
|
(Note 15) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(18) |
|
|
|
(18) |
|
|
|
|
|
|
|
|
|
Sale of Investment in PrairieSky |
|
(Note 15) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(133) |
|
|
|
(133) |
|
Balance, September 30, 2014 |
|
|
|
$ |
2,449 |
|
|
$ |
1,360 |
|
|
$ |
5,041 |
|
|
$ |
648 |
|
|
$ |
- |
|
|
$ |
9,498 |
|
See accompanying Notes to Condensed Consolidated Financial Statements
|
|
|
Condensed Consolidated Financial Statements
Prepared in accordance with U.S. GAAP in US$ |
|
|
Third quarter report
for the period ended September 30, 2015
Condensed
Consolidated Statement of Cash Flows (unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
September 30, |
|
|
Nine Months Ended
September 30, |
|
($ millions) |
|
|
|
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
|
Operating Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings (loss) |
|
|
|
|
|
$ |
(1,236) |
|
|
$ |
2,831 |
|
|
$ |
(4,553) |
|
|
$ |
3,228 |
|
|
|
|
|
|
|
Depreciation, depletion and amortization |
|
|
|
|
|
|
352 |
|
|
|
476 |
|
|
|
1,212 |
|
|
|
1,294 |
|
|
|
|
|
|
|
Impairments |
|
|
(Note 9) |
|
|
|
1,671 |
|
|
|
- |
|
|
|
5,668 |
|
|
|
- |
|
|
|
|
|
|
|
Accretion of asset retirement obligation |
|
|
(Note 12) |
|
|
|
11 |
|
|
|
13 |
|
|
|
34 |
|
|
|
39 |
|
|
|
|
|
|
|
Deferred income taxes |
|
|
(Note 8) |
|
|
|
(576) |
|
|
|
505 |
|
|
|
(2,442) |
|
|
|
825 |
|
|
|
|
|
|
|
Unrealized (gain) loss on risk management |
|
|
(Note 21) |
|
|
|
(173) |
|
|
|
(231) |
|
|
|
241 |
|
|
|
45 |
|
|
|
|
|
|
|
Unrealized foreign exchange (gain) loss |
|
|
(Note 7) |
|
|
|
241 |
|
|
|
247 |
|
|
|
555 |
|
|
|
266 |
|
|
|
|
|
|
|
Foreign exchange on settlements |
|
|
(Note 7) |
|
|
|
102 |
|
|
|
1 |
|
|
|
337 |
|
|
|
28 |
|
|
|
|
|
|
|
(Gain) loss on divestitures |
|
|
(Notes 5, 15) |
|
|
|
2 |
|
|
|
(3,239) |
|
|
|
(14) |
|
|
|
(3,442) |
|
|
|
|
|
|
|
Other |
|
|
|
|
|
|
(23) |
|
|
|
(51) |
|
|
|
9 |
|
|
|
19 |
|
|
|
|
|
|
|
Net change in other assets and liabilities |
|
|
|
|
|
|
(18) |
|
|
|
(11) |
|
|
|
(18) |
|
|
|
(28) |
|
|
|
|
|
|
|
Net change in non-cash working capital |
|
|
|
|
|
|
100 |
|
|
|
155 |
|
|
|
204 |
|
|
|
132 |
|
|
|
|
|
|
|
Cash From (Used in) Operating Activities |
|
|
|
|
|
|
453 |
|
|
|
696 |
|
|
|
1,233 |
|
|
|
2,406 |
|
|
|
|
|
|
|
Investing Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures |
|
|
(Note 3) |
|
|
|
(473) |
|
|
|
(598) |
|
|
|
(1,952) |
|
|
|
(1,669) |
|
|
|
|
|
|
|
Acquisitions |
|
|
(Note 5) |
|
|
|
- |
|
|
|
(29) |
|
|
|
(38) |
|
|
|
(2,975) |
|
|
|
|
|
|
|
Proceeds from divestitures |
|
|
(Note 5) |
|
|
|
99 |
|
|
|
2,036 |
|
|
|
1,115 |
|
|
|
4,354 |
|
|
|
|
|
|
|
Proceeds from sale of investment in PrairieSky |
|
|
(Notes 5, 15) |
|
|
|
- |
|
|
|
2,172 |
|
|
|
- |
|
|
|
2,172 |
|
|
|
|
|
|
|
Cash in reserve |
|
|
|
|
|
|
- |
|
|
|
111 |
|
|
|
72 |
|
|
|
(101) |
|
|
|
|
|
|
|
Net change in investments and other |
|
|
|
|
|
|
(170) |
|
|
|
113 |
|
|
|
(154) |
|
|
|
89 |
|
|
|
|
|
|
|
Cash From (Used in) Investing Activities |
|
|
|
|
|
|
(544) |
|
|
|
3,805 |
|
|
|
(957) |
|
|
|
1,870 |
|
|
|
|
|
|
|
Financing Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net issuance (repayment) of revolving long-term debt |
|
|
|
|
|
|
17 |
|
|
|
- |
|
|
|
137 |
|
|
|
- |
|
|
|
|
|
|
|
Repayment of long-term debt |
|
|
(Note 10) |
|
|
|
- |
|
|
|
- |
|
|
|
(1,302) |
|
|
|
(1,002) |
|
|
|
|
|
|
|
Issuance of common shares |
|
|
(Note 13) |
|
|
|
- |
|
|
|
- |
|
|
|
1,088 |
|
|
|
- |
|
|
|
|
|
|
|
Dividends on common shares |
|
|
(Note 13) |
|
|
|
(38) |
|
|
|
(51) |
|
|
|
(113) |
|
|
|
(152) |
|
|
|
|
|
|
|
Proceeds from sale of noncontrolling interest |
|
|
(Note 15) |
|
|
|
- |
|
|
|
(8) |
|
|
|
- |
|
|
|
1,463 |
|
|
|
|
|
|
|
Distributions to noncontrolling interest owners |
|
|
(Note 15) |
|
|
|
- |
|
|
|
(18) |
|
|
|
- |
|
|
|
(18) |
|
|
|
|
|
|
|
Capital lease payments and other financing arrangements |
|
|
(Note 11) |
|
|
|
(15) |
|
|
|
(18) |
|
|
|
(48) |
|
|
|
(60) |
|
|
|
|
|
|
|
Cash From (Used in) Financing Activities |
|
|
|
|
|
|
(36) |
|
|
|
(95) |
|
|
|
(238) |
|
|
|
231 |
|
|
|
|
|
|
|
Foreign Exchange Gain (Loss) on Cash and Cash
Equivalents Held in Foreign
Currency |
|
|
|
|
|
|
(17) |
|
|
|
(90) |
|
|
|
(24) |
|
|
|
(99) |
|
|
|
|
|
|
|
Increase (Decrease) in Cash and Cash Equivalents |
|
|
|
|
|
|
(144) |
|
|
|
4,316 |
|
|
|
14 |
|
|
|
4,408 |
|
|
|
|
|
|
|
Cash and Cash Equivalents, Beginning of Period |
|
|
|
|
|
|
496 |
|
|
|
2,658 |
|
|
|
338 |
|
|
|
2,566 |
|
|
|
|
|
|
|
Cash and Cash Equivalents, End of Period |
|
|
|
|
|
$ |
352 |
|
|
$ |
6,974 |
|
|
$ |
352 |
|
|
$ |
6,974 |
|
|
|
|
|
|
|
Cash, End of Period |
|
|
|
|
|
$ |
90 |
|
|
$ |
172 |
|
|
$ |
90 |
|
|
$ |
172 |
|
|
|
|
|
|
|
Cash Equivalents, End of Period |
|
|
|
|
|
|
262 |
|
|
|
6,802 |
|
|
|
262 |
|
|
|
6,802 |
|
|
|
|
|
|
|
Cash and Cash Equivalents, End of Period |
|
|
|
|
|
$ |
352 |
|
|
$ |
6,974 |
|
|
$ |
352 |
|
|
$ |
6,974 |
|
See accompanying Notes to Condensed Consolidated Financial Statements
|
|
|
|
|
Condensed Consolidated Financial Statements
Prepared in accordance with U.S. GAAP in US$ |
Third quarter report
for the period ended September 30, 2015
Notes to
Condensed Consolidated Financial Statements (unaudited)
(All amounts in $ millions unless otherwise
specified)
|
1. Basis of Presentation and Principles of Consolidation |
Encana Corporation and its subsidiaries (Encana or the Company) are in the business of the
exploration for, the development of, and the production and marketing of natural gas, oil and natural gas liquids (NGLs). The term liquids is used to represent Encanas oil, NGLs and condensate.
The interim Condensed Consolidated Financial Statements include the accounts of Encana and are presented in accordance with accounting principles
generally accepted in the United States (U.S. GAAP).
The interim Condensed Consolidated Financial Statements include the accounts of
Encana and entities in which it holds a controlling interest. The noncontrolling interest represented the third party equity ownership in a former consolidated subsidiary, PrairieSky Royalty Ltd. (PrairieSky), as presented in the
Condensed Consolidated Statement of Changes in Shareholders Equity. See Note 15 for further details regarding the noncontrolling interest. All intercompany balances and transactions are eliminated on consolidation. Undivided interests in
natural gas and oil exploration and production joint ventures and partnerships are consolidated on a proportionate basis. Investments in non-controlled entities over which Encana has the ability to exercise significant influence are accounted for
using the equity method.
The interim Condensed Consolidated Financial Statements have been prepared following the same accounting policies and
methods of computation as the annual audited Consolidated Financial Statements for the year ended December 31, 2014, except as noted below in Note 2. The disclosures provided below are incremental to those included with the annual audited
Consolidated Financial Statements. Certain information and disclosures normally required to be included in the notes to the annual audited Consolidated Financial Statements have been condensed or have been disclosed on an annual basis only.
Accordingly, the interim Condensed Consolidated Financial Statements should be read in conjunction with the annual audited Consolidated Financial Statements and the notes thereto for the year ended December 31, 2014.
These unaudited interim Condensed Consolidated Financial Statements reflect, in the opinion of Management, all normal and recurring adjustments
necessary to present fairly the financial position and results of the Company as at and for the periods presented. Interim condensed consolidated financial results are not necessarily indicative of consolidated financial results expected for the
fiscal year.
|
2. Recent Accounting Pronouncements |
Changes in Accounting Policies and Practices
On January 1, 2015, Encana adopted Accounting Standards Update (ASU) 2014-08, Reporting Discontinued Operations and Disclosures
of Disposals of Components of an Entity as issued by the Financial Accounting Standards Board (FASB). The update amends the criteria and expands the disclosures for reporting discontinued operations. Under the new criteria, only
disposals representing a strategic shift in operations would qualify as a discontinued operation. The amendments have been applied prospectively and have not had a material impact on the Companys interim Condensed Consolidated Financial
Statements.
|
|
|
Notes to Condensed Consolidated Financial Statements
Prepared in accordance with U.S. GAAP in US$ |
|
|
Third quarter report
for the period ended September 30, 2015
Notes to Condensed
Consolidated Financial Statements (unaudited)
(All amounts in $ millions unless
otherwise specified)
|
2. Recent Accounting Pronouncements (continued) |
New Standards Issued Not Yet Adopted
As of January 1, 2016, Encana will be required to adopt the following pronouncements issued by the FASB:
|
● |
|
ASU 2014-12, Compensation - Stock Compensation: Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could
Be Achieved After the Requisite Service Period. The update requires that a performance target that affects vesting and could be achieved after the requisite service period be treated as a performance condition. The amendments will be applied
prospectively and are not expected to have a material impact on the Companys Consolidated Financial Statements. |
|
● |
|
ASU 2015-02, Amendments to the Consolidation Analysis. The update requires limited partnerships and similar entities to be evaluated under the
variable interest and voting interest models, eliminate the presumption that a general partner should consolidate a limited partnership, and simplify the identification of variable interests and related effect on the primary beneficiary criterion
when fees are paid to a decision maker. The amendments can be applied using either a full retrospective approach or a modified retrospective approach at the date of adoption. Encana is currently assessing the potential impact of the amendments on
the Companys Consolidated Financial Statements. |
|
● |
|
ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs. The update requires debt issuance costs to be presented on the balance sheet as
a deduction from the carrying amount of the related liability. Previously, debt issuance costs were presented as a deferred charge within assets. In August 2015, the FASB issued ASU 2015-15, Presentation and Subsequent Measurement of Debt
Issuance Costs Associated with Line-of-Credit Arrangements. The update further clarifies that regardless of whether there are outstanding borrowings, debt issuance costs arising from credit arrangements can be presented as an asset and
subsequently amortized ratably over the term of the arrangement. These amendments will be applied retrospectively. As at September 30, 2015, $31 million of debt issuance costs were presented in Other Assets on the Companys interim
Condensed Consolidated Balance Sheet ($39 million as at December 31, 2014). |
As of January 1, 2018, Encana will be
required to adopt ASU 2014-09, Revenue from Contracts with Customers under Topic 606, which was the result of a joint project by the FASB and International Accounting Standards Board. The new standard replaces Topic 605, Revenue
Recognition, and other industry-specific guidance in the Accounting Standards Codification. The new standard is based on the principle that revenue is recognized on the transfer of promised goods or services to customers in an amount that
reflects the consideration the Company expects to be entitled to in exchange for those goods or services. In August 2015, the FASB issued ASU 2015-14, Deferral of Effective Date for Revenue from Contracts with Customers, which deferred
the effective date of ASU 2014-09, but permits early adoption using the original effective date of January 1, 2017. The standard can be applied using one of two retrospective application methods at the date of adoption. Encana is currently
assessing the potential impact of the standard on the Companys Consolidated Financial Statements.
Encanas reportable segments are determined based on the Companys operations and geographic locations as
follows:
● |
|
Canadian Operations includes the exploration for, development of, and production of natural gas, oil and NGLs and other related activities within the
Canadian cost centre. |
● |
|
USA Operations includes the exploration for, development of, and production of natural gas, oil and NGLs and other related activities within the U.S.
cost centre. |
● |
|
Market Optimization is primarily responsible for the sale of the Companys 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 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 Companys upstream production to third party customers. Transactions between segments are based on market values and are eliminated on
consolidation. |
Corporate and Other mainly includes unrealized gains or losses recorded on derivative financial instruments. Once
the instruments are settled, the realized gains and losses are recorded in the reporting segment to which the derivative instruments relate.
|
|
|
|
|
Notes to Condensed Consolidated Financial Statements
Prepared in accordance with U.S. GAAP in US$ |
Third quarter report
for the period ended September 30, 2015
Notes to Condensed
Consolidated Financial Statements (unaudited)
(All amounts in $ millions unless
otherwise specified)
|
3. Segmented Information (continued) |
Results of Operations (For the three months ended September 30)
Segment and Geographic Information
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
USA Operations |
|
Market Optimization |
|
|
2015 |
|
|
2014 |
|
2015 |
|
|
2014 |
|
2015 |
|
|
2014 |
Revenues, Net of
Royalties |
|
$ |
391 |
|
|
$ 759 |
|
$ |
655 |
|
|
$ 780 |
|
$ |
66 |
|
|
$ 486 |
|
|
|
|
|
|
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and mineral taxes |
|
|
- |
|
|
4 |
|
|
27 |
|
|
13 |
|
|
- |
|
|
- |
Transportation and processing |
|
|
153 |
|
|
202 |
|
|
155 |
|
|
166 |
|
|
- |
|
|
- |
Operating |
|
|
38 |
|
|
76 |
|
|
142 |
|
|
96 |
|
|
4 |
|
|
11 |
Purchased product |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
60 |
|
|
474 |
|
|
|
200 |
|
|
477 |
|
|
331 |
|
|
505 |
|
|
2 |
|
|
1 |
Depreciation, depletion and
amortization |
|
|
64 |
|
|
166 |
|
|
265 |
|
|
279 |
|
|
- |
|
|
- |
Impairments |
|
|
- |
|
|
- |
|
|
1,671 |
|
|
- |
|
|
- |
|
|
- |
|
|
$ |
136 |
|
|
$ 311 |
|
$ |
(1,605) |
|
|
$ 226 |
|
$ |
2 |
|
|
$ 1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate & Other
|
|
Consolidated |
|
|
|
|
|
|
|
2015 |
|
|
2014 |
|
2015 |
|
|
2014 |
|
|
|
|
|
|
|
Revenues, Net of Royalties |
|
|
|
|
|
|
|
$ |
200 |
|
|
$ 260 |
|
$ |
1,312 |
|
|
$ 2,285 |
|
|
|
|
|
|
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and mineral
taxes |
|
|
- |
|
|
- |
|
|
27 |
|
|
17 |
Transportation and
processing |
|
|
11 |
|
|
2 |
|
|
319 |
|
|
370 |
Operating |
|
|
6 |
|
|
7 |
|
|
190 |
|
|
190 |
Purchased product |
|
|
- |
|
|
- |
|
|
60 |
|
|
474 |
|
|
|
|
|
|
|
|
|
183 |
|
|
251 |
|
|
716 |
|
|
1,234 |
Depreciation, depletion and
amortization |
|
|
23 |
|
|
31 |
|
|
352 |
|
|
476 |
Impairments |
|
|
|
|
|
|
|
|
- |
|
|
- |
|
|
1,671 |
|
|
- |
|
|
|
|
|
|
|
|
$ |
160 |
|
|
$ 220 |
|
|
(1,307 |
) |
|
758 |
Accretion of asset
retirement obligation |
|
|
|
|
|
|
|
|
11 |
|
|
13 |
Administrative |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
61 |
|
|
69 |
Interest |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
105 |
|
|
133 |
Foreign exchange (gain)
loss, net |
|
|
|
|
|
|
|
|
348 |
|
|
202 |
(Gain) loss on
divestitures |
|
|
|
|
|
|
|
|
2 |
|
|
(3,239) |
Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3 |
) |
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
524 |
|
|
(2,822) |
Net Earnings (Loss) Before Income Tax |
|
|
|
|
|
(1,831 |
) |
|
3,580 |
Income tax expense (recovery) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(595 |
) |
|
749 |
Net Earnings (Loss) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,236 |
) |
|
2,831 |
Net earnings attributable to noncontrolling interest |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
- |
|
|
(24) |
Net Earnings (Loss) Attributable to Common Shareholders |
|
|
|
|
|
|
|
$ |
(1,236 |
) |
|
$ 2,807 |
Intersegment Information
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Market Optimization |
|
|
Marketing Sales |
|
Upstream Eliminations |
|
Total |
|
|
2015 |
|
|
2014 |
|
2015 |
|
|
2014 |
|
2015 |
|
|
2014 |
|
|
|
|
|
|
|
Revenues, Net of Royalties |
|
$ |
1,063 |
|
|
$ 1,732 |
|
$ |
(997 |
) |
|
$ (1,246) |
|
$ |
66 |
|
|
$ 486 |
|
|
|
|
|
|
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transportation and processing |
|
|
77 |
|
|
108 |
|
|
(77 |
) |
|
(108) |
|
|
- |
|
|
- |
Operating |
|
|
4 |
|
|
15 |
|
|
- |
|
|
(4) |
|
|
4 |
|
|
11 |
Purchased product |
|
|
980 |
|
|
1,600 |
|
|
(920 |
) |
|
(1,126) |
|
|
60 |
|
|
474 |
Operating Cash Flow |
|
$ |
2 |
|
|
$ 9 |
|
$ |
- |
|
|
$ (8) |
|
$ |
2 |
|
|
$ 1 |
|
|
|
Notes to Condensed Consolidated Financial Statements
Prepared in accordance with U.S. GAAP in US$ |
|
|
Third quarter report
for the period ended September 30, 2015
Notes to Condensed
Consolidated Financial Statements (unaudited)
(All amounts in $ millions unless
otherwise specified)
|
3. Segmented Information (continued) |
Results of Operations (For the nine months ended September 30)
Segment and Geographic Information
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
USA Operations |
|
Market Optimization |
|
|
2015 |
|
|
2014 |
|
2015 |
|
|
2014 |
|
2015 |
|
|
2014 |
Revenues, Net of
Royalties |
|
$ |
1,410 |
|
|
$ 2,706 |
|
$ |
1,872 |
|
|
$ 2,131 |
|
$ |
293 |
|
|
$ 890 |
|
|
|
|
|
|
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and mineral taxes |
|
|
- |
|
|
13 |
|
|
72 |
|
|
84 |
|
|
- |
|
|
- |
Transportation and processing |
|
|
501 |
|
|
642 |
|
|
454 |
|
|
506 |
|
|
- |
|
|
- |
Operating |
|
|
125 |
|
|
246 |
|
|
418 |
|
|
249 |
|
|
28 |
|
|
37 |
Purchased product |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
260 |
|
|
844 |
|
|
|
784 |
|
|
1,805 |
|
|
928 |
|
|
1,292 |
|
|
5 |
|
|
9 |
Depreciation, depletion and
amortization |
|
|
237 |
|
|
503 |
|
|
902 |
|
|
694 |
|
|
- |
|
|
4 |
Impairments |
|
|
- |
|
|
- |
|
|
5,668 |
|
|
- |
|
|
- |
|
|
- |
|
|
$ |
547 |
|
|
$ 1,302 |
|
$ |
(5,642) |
|
|
$ 598 |
|
$ |
5 |
|
|
$ 5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate & Other |
|
Consolidated |
|
|
|
|
|
|
|
2015 |
|
|
2014 |
|
2015 |
|
|
2014 |
Revenues, Net of
Royalties |
|
|
|
|
|
|
|
$ |
(184 |
) |
|
$ 38 |
|
$ |
3,391 |
|
|
$ 5,765 |
|
|
|
|
|
|
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and mineral
taxes |
|
|
- |
|
|
- |
|
|
72 |
|
|
97 |
Transportation and
processing |
|
|
4 |
|
|
1 |
|
|
959 |
|
|
1,149 |
Operating |
|
|
17 |
|
|
25 |
|
|
588 |
|
|
557 |
Purchased product |
|
|
- |
|
|
- |
|
|
260 |
|
|
844 |
|
|
|
|
|
|
|
|
|
(205 |
) |
|
12 |
|
|
1,512 |
|
|
3,118 |
Depreciation, depletion and
amortization |
|
|
73 |
|
|
93 |
|
|
1,212 |
|
|
1,294 |
Impairments |
|
|
|
|
|
|
|
|
- |
|
|
- |
|
|
5,668 |
|
|
- |
|
|
|
|
|
|
|
|
$ |
(278 |
) |
|
$ (81) |
|
|
(5,368 |
) |
|
1,824 |
Accretion of asset retirement obligation |
|
|
|
|
|
|
|
|
34 |
|
|
39 |
Administrative |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
217 |
|
|
269 |
Interest |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
508 |
|
|
402 |
Foreign exchange (gain)
loss, net |
|
|
|
|
|
|
|
|
918 |
|
|
254 |
(Gain) loss on
divestitures |
|
|
|
|
|
|
|
|
(14 |
) |
|
(3,442) |
Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2 |
|
|
8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,665 |
|
|
(2,470) |
Net Earnings (Loss) Before Income Tax |
|
|
|
|
|
(7,033 |
) |
|
4,294 |
Income tax expense (recovery) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,480 |
) |
|
1,066 |
Net Earnings (Loss) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(4,553 |
) |
|
3,228 |
Net earnings attributable to noncontrolling interest |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
- |
|
|
(34) |
Net Earnings (Loss) Attributable to Common Shareholders |
|
|
|
|
|
|
|
$ |
(4,553 |
) |
|
$ 3,194 |
Intersegment Information
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Market Optimization |
|
|
Marketing Sales |
|
Upstream Eliminations |
|
Total |
|
|
2015 |
|
|
2014 |
|
2015 |
|
|
2014 |
|
2015 |
|
|
2014 |
|
|
|
|
|
|
|
Revenues, Net of Royalties |
|
$ |
3,345 |
|
|
$ 5,740 |
|
$ |
(3,052 |
) |
|
$ (4,850) |
|
$ |
293 |
|
|
$ 890 |
|
|
|
|
|
|
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transportation and processing |
|
|
261 |
|
|
358 |
|
|
(261 |
) |
|
(358) |
|
|
- |
|
|
- |
Operating |
|
|
28 |
|
|
59 |
|
|
- |
|
|
(22) |
|
|
28 |
|
|
37 |
Purchased product |
|
|
3,051 |
|
|
5,303 |
|
|
(2,791 |
) |
|
(4,459) |
|
|
260 |
|
|
844 |
Operating Cash Flow |
|
$ |
5 |
|
|
$ 20 |
|
$ |
- |
|
|
$ (11) |
|
$ |
5 |
|
|
$ 9 |
|
|
|
|
|
Notes to Condensed Consolidated Financial Statements
Prepared in accordance with U.S. GAAP in US$ |
Third quarter report
for the period ended September 30, 2015
Notes to Condensed
Consolidated Financial Statements (unaudited)
(All amounts in $ millions unless
otherwise specified)
|
3. Segmented Information (continued) |
Capital Expenditures
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
|
|
|
|
|
|
|
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
Canadian Operations |
|
|
$ |
76 |
|
|
$ |
293 |
|
|
$ |
341 |
|
|
$ |
924 |
|
|
|
|
|
|
USA Operations |
|
|
|
394 |
|
|
|
305 |
|
|
|
1,605 |
|
|
|
737 |
|
|
|
|
|
|
Market Optimization |
|
|
|
1 |
|
|
|
(2) |
|
|
|
1 |
|
|
|
- |
|
|
|
|
|
|
Corporate & Other |
|
|
|
2 |
|
|
|
2 |
|
|
|
5 |
|
|
|
8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
473 |
|
|
$ |
598 |
|
|
$ |
1,952 |
|
|
$ |
1,669 |
|
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, |
|
|
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
|
|
Canadian Operations |
|
$ |
683 |
|
|
$ |
788 |
|
|
$ |
1,184 |
|
|
$ |
2,338 |
|
|
$ |
2,177 |
|
|
$ |
3,632 |
|
|
|
|
|
|
|
|
USA Operations |
|
|
2,129 |
|
|
|
2,129 |
|
|
|
8,725 |
|
|
|
13,817 |
|
|
|
11,351 |
|
|
|
16,800 |
|
|
|
|
|
|
|
|
Market Optimization |
|
|
- |
|
|
|
- |
|
|
|
1 |
|
|
|
1 |
|
|
|
57 |
|
|
|
181 |
|
|
|
|
|
|
|
|
Corporate & Other |
|
|
- |
|
|
|
- |
|
|
|
1,572 |
|
|
|
1,859 |
|
|
|
3,709 |
|
|
|
4,008 |
|
|
|
|
|
|
|
|
|
|
$ |
2,812 |
|
|
$ |
2,917 |
|
|
$ |
11,482 |
|
|
$ |
18,015 |
|
|
$ |
17,294 |
|
|
$ |
24,621 |
|
Eagle Ford Acquisition
On
June 20, 2014, Encana completed the acquisition of properties located in the Eagle Ford shale formation for approximately $2.9 billion, after closing adjustments. The acquisition included an interest in certain producing properties and
undeveloped lands in the Karnes, Wilson and Atascosa counties of south Texas. Encana funded the acquisition with cash on hand. Transaction costs of approximately $9 million were included in other expenses.
Athlon Energy Inc. Acquisition
On November 13, 2014,
Encana completed the acquisition of all of the issued and outstanding shares of common stock of Athlon Energy Inc. (Athlon) for $5.93 billion, or $58.50 per share. In addition, Encana assumed Athlons $1.15 billion senior notes and
repaid and terminated Athlons credit facility with indebtedness outstanding of $335 million. Encana funded the acquisition of Athlon with cash on hand. Transaction costs of approximately $31 million were included in other expenses. Following
completion of the acquisition, Athlons $1.15 billion senior notes were redeemed in accordance with the provisions of the governing indentures. Athlons operations focused on the acquisition and development of oil and gas properties
located in the Permian Basin in Texas.
|
|
|
Notes to Condensed Consolidated Financial Statements
Prepared in accordance with U.S. GAAP in US$ |
|
|
Third quarter report
for the period ended September 30, 2015
Notes to Condensed
Consolidated Financial Statements (unaudited)
(All amounts in $ millions unless
otherwise specified)
|
4. Business Combinations (continued) |
Purchase Price Allocations
The transactions were accounted for under the acquisition method, which requires that the assets acquired and liabilities assumed be recognized at their
fair values as of the acquisition date. The purchase price allocations, representing consideration paid and the fair values of the assets acquired and liabilities assumed as of the acquisition date, are shown in the table below.
|
|
|
|
|
|
|
Purchase Price Allocation |
|
Eagle Ford (1) |
|
|
Athlon (2, 3) |
|
|
|
Assets Acquired: |
|
|
|
|
|
|
Cash |
|
$ |
- |
|
|
$ 2 |
Accounts receivable and other current assets |
|
|
4 |
|
|
133 |
Risk management |
|
|
- |
|
|
80 |
Proved properties |
|
|
2,873 |
|
|
2,124 |
Unproved properties |
|
|
78 |
|
|
5,338 |
Other property, plant and equipment |
|
|
- |
|
|
2 |
Other assets |
|
|
- |
|
|
2 |
Goodwill |
|
|
- |
|
|
1,724 |
Liabilities Assumed: |
|
|
|
|
|
|
Accounts payable and accrued liabilities |
|
|
- |
|
|
(195) |
Long-term debt, including revolving credit facility |
|
|
- |
|
|
(1,497) |
Asset retirement obligation |
|
|
(32) |
|
|
(25) |
Deferred income taxes |
|
|
- |
|
|
(1,724) |
Total Purchase Price |
|
$ |
2,923 |
|
|
$ 5,964 |
(1) The purchase price allocation for Eagle Ford is finalized.
(2) The purchase price
allocation for Athlon is preliminary. There were no changes during the nine months ended September 30, 2015.
(3) The purchase price includes cash consideration
paid for issued and outstanding shares of common stock of Athlon of $58.50 per share totaling $5.93 billion, as well as
payments to terminate certain employment agreements with Athlons management
and payments for certain other existing obligations of Athlon. The Company used
the income approach valuation technique for the fair value of assets acquired and liabilities assumed. The carrying amounts of cash, accounts receivable and other current assets, and accounts payable and accrued liabilities approximate their fair
values due to the short-term maturity of the instruments. The fair values of the risk management assets and long-term debt, including the revolving credit facility, are categorized within Level 2 of the fair value hierarchy and were determined using
quoted prices and rates from an available pricing source. The fair values of the proved and unproved properties, other property, plant and equipment, other assets, goodwill, and asset retirement obligation are categorized within Level 3 and were
determined using relevant market assumptions, including discount rates, future commodity prices and costs, timing of development activities, projections of oil and gas reserves, and estimates to abandon and reclaim producing wells.
Goodwill arose from the Athlon acquisition primarily from the
requirement to recognize deferred taxes on the difference between the fair value of the assets acquired and liabilities assumed and the respective carry-over tax basis. Goodwill is not amortized and is not deductible for tax purposes.
Pro Forma Financial Information
The following unaudited pro forma financial information combines the historical
financial results of Encana with Eagle Ford and Athlon, and has been prepared assuming the acquisitions occurred on January 1, 2014. The pro forma information is not intended to reflect the actual results of operations that would have occurred
if the business combinations had been completed at the date indicated. In addition, the pro forma information does not project Encanas results of operations for any future period. The Companys consolidated results for the nine months
ended September 30, 2015 include the results from Eagle Ford and Athlon. |
Nine Months Ended September 30, 2014 ($ millions, except per share amounts) |
|
Eagle Ford |
|
|
Athlon |
|
|
|
Revenues, Net of Royalties |
|
$ |
6,506 |
|
|
$ 6,188 |
Net Earnings Attributable to Common Shareholders |
|
$ |
3,445 |
|
|
$ 3,258 |
|
|
|
Net Earnings per Common Share |
|
|
|
|
|
|
Basic & Diluted |
|
$ |
4.65 |
|
|
$ 4.40 |
|
|
|
|
|
Notes to Condensed Consolidated Financial Statements
Prepared in accordance with U.S. GAAP in US$ |
Third quarter report
for the period ended September 30, 2015
Notes to Condensed
Consolidated Financial Statements (unaudited)
(All amounts in $ millions unless
otherwise specified)
|
5. Acquisitions and Divestitures |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
|
Nine Months Ended
September 30, |
|
|
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
Acquisitions |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
$ |
- |
|
|
$ |
12 |
|
|
$ |
1 |
|
|
$ |
14 |
|
USA Operations |
|
|
- |
|
|
|
17 |
|
|
|
3 |
|
|
|
2,961 |
|
Corporate & Other |
|
|
- |
|
|
|
- |
|
|
|
34 |
|
|
|
- |
|
Total Acquisitions |
|
|
- |
|
|
|
29 |
|
|
|
38 |
|
|
|
2,975 |
|
|
|
|
|
|
Divestitures |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
|
(56) |
|
|
|
(1,729) |
|
|
|
(935) |
|
|
|
(1,850) |
|
USA Operations |
|
|
(43) |
|
|
|
(100) |
|
|
|
(127) |
|
|
|
(2,270) |
|
Market Optimization |
|
|
- |
|
|
|
(205) |
|
|
|
- |
|
|
|
(205) |
|
Corporate & Other |
|
|
- |
|
|
|
(2) |
|
|
|
(53) |
|
|
|
(29) |
|
Total Divestitures |
|
|
(99) |
|
|
|
(2,036) |
|
|
|
(1,115) |
|
|
|
(4,354) |
|
Net Acquisitions & (Divestitures) |
|
$ |
(99) |
|
|
$ |
(2,007) |
|
|
$ |
(1,077) |
|
|
$ |
(1,379) |
|
Acquisitions
During the nine
months ended September 30, 2014, acquisitions primarily included the purchase of certain properties in the Eagle Ford shale formation in south Texas as described in Note 4.
Divestitures
For the three and nine months ended
September 30, 2015, divestitures in the Canadian Operations were $56 million and $935 million, respectively. Divestitures primarily reflect the sale of certain assets included in Wheatland located in central and southern Alberta for proceeds of
approximately C$558 million ($468 million), after closing adjustments, the sale of certain natural gas gathering and compression assets in the Montney area of northeastern British Columbia for proceeds of approximately C$453 million ($357 million),
after closing adjustments, and the sale of land and properties that do not complement Encanas existing portfolio of assets. During the three and nine months ended September 30, 2014, divestitures in the Canadian Operations were $1,729
million and $1,850 million, respectively, which primarily included the sale of the Companys Bighorn assets in west central Alberta.
For the
three and nine months ended September 30, 2015, divestitures in the USA Operations were $43 million and $127 million, respectively, which primarily included the sale of land and properties that do not complement Encanas existing portfolio
of assets. During the three and nine months ended September 30, 2014, divestitures in the USA Operations were $100 million and $2,270 million, respectively. During the nine months ended September 30, 2014, divestitures primarily included
the sale of the Jonah properties for proceeds of approximately $1,639 million and the sale of certain properties in East Texas for proceeds of approximately $497 million.
Encana recognizes gains or losses on 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, 2014, Encana recognized a gain of approximately $1,024
million, before tax, on the sale of the Companys Bighorn assets in the Canadian cost centre and allocated goodwill of $257 million. In addition, for the nine months ended September 30, 2014, Encana recognized a gain of approximately $212
million, before tax, on the sale of the Jonah properties in the U.S. cost centre and allocated goodwill of $68 million.
Amounts received from the
divestiture transactions have been deducted from the respective Canadian and U.S. full cost pools, except for the sale of the Bighorn assets and the Jonah properties as noted above and the sale of the investment in PrairieSky as noted below.
For the nine months ended September 30, 2015, Corporate and Other acquisitions and divestitures primarily includes the purchase and subsequent sale
of the Encana Place office building located in Calgary, which resulted in a gain on divestiture of approximately $12 million.
Divestiture of Investment in
PrairieSky
On September 26, 2014, Encana completed the secondary offering of 70.2 million common shares of PrairieSky at a price of
C$36.50 per common share for aggregate gross proceeds of approximately C$2.6 billion. As the sale of the investment in PrairieSky resulted in a significant alteration between capitalized costs and proved reserves in the Canadian cost centre, Encana
recognized a gain on divestiture of approximately $2.1 billion, before tax. See Note 15 for further details regarding the PrairieSky transactions.
|
|
|
Notes to Condensed Consolidated Financial Statements
Prepared in accordance with U.S. GAAP in US$ |
|
|
Third quarter report
for the period ended September 30, 2015
Notes to Condensed
Consolidated Financial Statements (unaudited)
(All amounts in $ millions unless
otherwise specified)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
|
|
|
|
|
Interest Expense on: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Debt |
|
$ |
77 |
|
|
$ |
95 |
|
|
$ |
420 |
|
|
$ 303 |
The Bow office building |
|
|
15 |
|
|
|
19 |
|
|
|
49 |
|
|
57 |
Capital leases |
|
|
7 |
|
|
|
9 |
|
|
|
22 |
|
|
28 |
Other |
|
|
6 |
|
|
|
10 |
|
|
|
17 |
|
|
14 |
|
|
$ |
105 |
|
|
$ |
133 |
|
|
$ |
508 |
|
|
$ 402 |
Interest Expense on Debt for the nine months ended
September 30, 2015 includes a one-time interest payment of approximately $165 million resulting from the April 2015 early redemption of the Companys $700 million 5.90 percent notes due December 1, 2017 and C$750 million 5.80 percent
medium-term notes due January 18, 2018 as discussed in Note 10. |
7. Foreign Exchange (Gain) Loss, Net |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
September 30, |
|
|
Nine Months Ended
September 30, |
|
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
|
|
|
|
|
Unrealized Foreign Exchange (Gain) Loss on: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Translation of U.S. dollar debt issued from Canada |
|
$ |
297 |
|
|
$ |
256 |
|
|
$ |
638 |
|
|
$ 276 |
Translation of U.S. dollar risk management contracts
issued from Canada |
|
|
(27) |
|
|
|
(9) |
|
|
|
(56) |
|
|
(10) |
Translation of intercompany notes |
|
|
(29) |
|
|
|
- |
|
|
|
(27) |
|
|
- |
|
|
|
241 |
|
|
|
247 |
|
|
|
555 |
|
|
266 |
Foreign Exchange on Settlements |
|
|
102 |
|
|
|
1 |
|
|
|
337 |
|
|
28 |
|
|
|
|
|
Other Monetary Revaluations |
|
|
5 |
|
|
|
(46) |
|
|
|
26 |
|
|
(40) |
|
|
$ |
348 |
|
|
$ |
202 |
|
|
$ |
918 |
|
|
$ 254 |
Foreign Exchange on Settlements includes foreign
exchange on intercompany transactions and foreign exchange on settlement of long-term debt previously reported in Other Monetary Revaluations. |
8. Income Taxes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
September 30, |
|
|
Nine Months Ended
September 30, |
|
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
|
|
|
|
|
Current Tax |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada |
|
$ |
1 |
|
|
$ |
267 |
|
|
$ |
(24) |
|
|
$ 247 |
United States |
|
|
(22) |
|
|
|
(26) |
|
|
|
(19) |
|
|
(19) |
Other countries |
|
|
2 |
|
|
|
3 |
|
|
|
5 |
|
|
13 |
Total Current Tax Expense (Recovery) |
|
|
(19) |
|
|
|
244 |
|
|
|
(38) |
|
|
241 |
|
|
|
|
|
Deferred Tax |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada |
|
|
(138) |
|
|
|
470 |
|
|
|
(616) |
|
|
698 |
United States |
|
|
(471) |
|
|
|
36 |
|
|
|
(2,110) |
|
|
107 |
Other countries |
|
|
33 |
|
|
|
(1) |
|
|
|
284 |
|
|
20 |
Total Deferred Tax Expense (Recovery) |
|
|
(576) |
|
|
|
505 |
|
|
|
(2,442) |
|
|
825 |
|
|
$ |
(595) |
|
|
$ |
749 |
|
|
$ |
(2,480) |
|
|
$ 1,066 |
Encanas interim income tax expense is determined using an estimated annual effective income tax rate applied to
year-to-date net earnings before income tax plus the effect of legislative changes, including the 2015 Alberta general corporate income tax rate increase, and amounts in respect of prior periods. The estimated annual effective income tax rate is
impacted by the expected annual earnings, statutory rate and other foreign differences, non-taxable capital gains and losses, tax differences on divestitures and transactions, and partnership tax allocations in excess of funding.
|
|
|
|
|
Notes to Condensed Consolidated Financial Statements
Prepared in accordance with U.S. GAAP in US$ |
Third quarter report
for the period ended September 30, 2015
Notes to Condensed
Consolidated Financial Statements (unaudited)
(All amounts in $ millions unless
otherwise specified)
|
9. Property, Plant and Equipment, Net |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As at September 30, 2015 |
|
|
As at December 31, 2014 |
|
|
|
Cost |
|
|
Accumulated
DD&A
(1) |
|
|
Net |
|
|
Cost |
|
|
Accumulated
DD&A
(1) |
|
|
Net |
|
|
|
|
|
|
|
|
Canadian Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved properties |
|
$ |
15,286 |
|
|
$ |
(14,574) |
|
|
$ |
712 |
|
|
$ |
18,271 |
|
|
$ |
(16,566) |
|
|
$ |
1,705 |
|
Unproved properties |
|
|
380 |
|
|
|
- |
|
|
|
380 |
|
|
|
478 |
|
|
|
- |
|
|
|
478 |
|
Other |
|
|
92 |
|
|
|
- |
|
|
|
92 |
|
|
|
155 |
|
|
|
- |
|
|
|
155 |
|
|
|
|
15,758 |
|
|
|
(14,574) |
|
|
|
1,184 |
|
|
|
18,904 |
|
|
|
(16,566) |
|
|
|
2,338 |
|
|
|
|
|
|
|
|
USA Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved properties |
|
|
26,111 |
|
|
|
(22,829) |
|
|
|
3,282 |
|
|
|
24,279 |
|
|
|
(16,260) |
|
|
|
8,019 |
|
Unproved properties |
|
|
5,354 |
|
|
|
- |
|
|
|
5,354 |
|
|
|
5,655 |
|
|
|
- |
|
|
|
5,655 |
|
Other |
|
|
89 |
|
|
|
- |
|
|
|
89 |
|
|
|
143 |
|
|
|
- |
|
|
|
143 |
|
|
|
|
31,554 |
|
|
|
(22,829) |
|
|
|
8,725 |
|
|
|
30,077 |
|
|
|
(16,260) |
|
|
|
13,817 |
|
|
|
|
|
|
|
|
Market Optimization |
|
|
7 |
|
|
|
(6) |
|
|
|
1 |
|
|
|
8 |
|
|
|
(7) |
|
|
|
1 |
|
Corporate & Other |
|
|
2,160 |
|
|
|
(588) |
|
|
|
1,572 |
|
|
|
2,470 |
|
|
|
(611) |
|
|
|
1,859 |
|
|
|
$ |
49,479 |
|
|
$ |
(37,997) |
|
|
$ |
11,482 |
|
|
$ |
51,459 |
|
|
$ |
(33,444) |
|
|
$ |
18,015 |
|
(1) Depreciation, depletion and amortization.
Canadian Operations and USA Operations property, plant and equipment include internal costs directly related to exploration, development and
construction activities of $170 million which have been capitalized during the nine months ended September 30, 2015 (2014 - $255 million). Included in Corporate and Other are $56 million ($65 million as at December 31, 2014) of
international property costs, which have been fully impaired.
For the three and nine months ended September 30, 2015, the Company recognized
before-tax ceiling test impairments of $1,671 million and $5,668 million, respectively (2014 - nil) in the U.S. cost centre, which are included within accumulated DD&A in the table above. The impairments resulted primarily from the decline in
the 12-month average trailing commodity prices which reduced proved reserves volumes and values. There were no ceiling test impairments in the Canadian cost centre for the three and nine months ended September 30, 2015 (2014 - nil).
The 12-month average trailing prices used in the ceiling test calculations were based on the benchmark prices below. The benchmark prices were adjusted
for basis differentials to determine local reference prices, transportation costs and tariffs, heat content and quality.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas |
|
|
Oil & NGLs |
|
|
|
Henry Hub ($/MMBtu) |
|
|
AECO (C$/MMBtu) |
|
|
WTI ($/bbl) |
|
|
Edmonton Light Sweet (C$/bbl) |
|
12-Month Average Trailing Reserves Pricing |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2015 |
|
|
3.05 |
|
|
|
3.02 |
|
|
|
59.21 |
|
|
|
65.69 |
|
December 31, 2014 |
|
|
4.34 |
|
|
|
4.63 |
|
|
|
94.99 |
|
|
|
96.40 |
|
September 30, 2014 |
|
|
4.24 |
|
|
|
4.49 |
|
|
|
99.08 |
|
|
|
96.92 |
|
Capital Lease Arrangements
The Company has several lease arrangements that are accounted for as capital leases, including an office building, equipment and an offshore production
platform.
In December 2013, Encana commenced commercial operations at its Deep Panuke facility located offshore Nova Scotia at which time the
Company recorded a capital lease asset and a corresponding capital lease obligation related to the Production Field Centre (PFC). Variable interests related to the PFC are described in Note 16.
As at September 30, 2015, the total carrying value of assets under capital lease was $402 million ($547 million as at December 31, 2014).
Liabilities for the capital lease arrangements are included in other liabilities and provisions in the Condensed Consolidated Balance Sheet and are disclosed in Note 11.
|
|
|
Notes to Condensed Consolidated Financial Statements
Prepared in accordance with U.S. GAAP in US$ |
|
|
Third quarter report
for the period ended September 30, 2015
Notes to Condensed
Consolidated Financial Statements (unaudited)
(All amounts in $ millions unless
otherwise specified)
|
9. Property, Plant and Equipment, Net (continued) |
Other Arrangement
As at September 30, 2015, Corporate and Other property, plant and equipment and total assets include a carrying value of $1,223 million ($1,431
million as at December 31, 2014) related to The Bow office building, which is under a 25-year lease agreement. The Bow asset is being depreciated over the 60-year estimated life of the building. At the conclusion of the 25-year term, the
remaining asset and corresponding liability are expected to be derecognized as disclosed in Note 11.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
C$
Principal Amount |
|
|
As at September 30, 2015 |
|
|
As at
December 31, 2014 |
|
|
|
|
|
Canadian Dollar Denominated Debt |
|
|
|
|
|
|
|
|
|
|
|
|
5.80% due January 18, 2018 |
|
$ |
-
|
|
|
$ |
- |
|
|
$ |
647 |
|
|
|
|
|
U.S. Dollar Denominated Debt |
|
|
|
|
|
|
|
|
|
|
|
|
Revolving credit and term loan borrowings |
|
|
|
|
|
|
1,414 |
|
|
|
1,277 |
|
U.S. Unsecured Notes |
|
|
|
|
|
|
|
|
|
|
|
|
5.90% due December 1, 2017 |
|
|
|
|
|
|
- |
|
|
|
700 |
|
6.50% due May 15, 2019 |
|
|
|
|
|
|
500 |
|
|
|
500 |
|
3.90% due November 15, 2021 |
|
|
|
|
|
|
600 |
|
|
|
600 |
|
8.125% due September 15, 2030 |
|
|
|
|
|
|
300 |
|
|
|
300 |
|
7.20% due November 1, 2031 |
|
|
|
|
|
|
350 |
|
|
|
350 |
|
7.375% due November 1, 2031 |
|
|
|
|
|
|
500 |
|
|
|
500 |
|
6.50% due August 15, 2034 |
|
|
|
|
|
|
750 |
|
|
|
750 |
|
6.625% due August 15, 2037 |
|
|
|
|
|
|
500 |
|
|
|
500 |
|
6.50% due February 1, 2038 |
|
|
|
|
|
|
800 |
|
|
|
800 |
|
5.15% due November 15, 2041 |
|
|
|
|
|
|
400 |
|
|
|
400 |
|
|
|
|
|
|
|
|
6,114 |
|
|
|
6,677 |
|
Total Principal |
|
|
|
|
|
|
6,114 |
|
|
|
7,324 |
|
|
|
|
|
Increase in Value of Debt Acquired |
|
|
|
|
|
|
28 |
|
|
|
34 |
|
Debt Discounts |
|
|
|
|
|
|
(14) |
|
|
|
(18) |
|
Current Portion of Long-Term Debt |
|
|
|
|
|
|
- |
|
|
|
- |
|
|
|
|
|
|
|
$ |
6,128 |
|
|
$ |
7,340 |
|
Long-term debt is accounted for at amortized cost using the effective interest method of amortization. As at
September 30, 2015, total long-term debt had a carrying value of $6,128 million and a fair value of $5,870 million (as at December 31, 2014 - carrying value of $7,340 million and a fair value of $7,788 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, or by discounting future payments of interest and principal at interest rates expected to be available to the Company
at period end.
On March 5, 2015, Encana provided notice to note holders that it would redeem the Companys $700 million 5.90 percent notes
due December 1, 2017 and C$750 million 5.80 percent medium-term notes due January 18, 2018. On April 6, 2015, the Company used net proceeds from the common shares issued, as disclosed in Note 13, and cash on hand to complete the note
redemptions. In conjunction with the early note redemptions, the Company incurred a one-time interest payment of approximately $165 million as discussed in Note 6.
On February 28, 2014, Encana announced a cash tender offer and consent solicitation for any and all of the Companys outstanding $1,000 million
5.80 percent notes with a maturity date of May 1, 2014. The Company paid $1,004.59 for each $1,000 principal amount of the notes plus accrued and unpaid interest up to, but not including, the settlement date and a consent payment equal to $2.50
per $1,000 principal amount of the notes.
On March 28, 2014, the tender offer and consent solicitation expired and on March 31, 2014,
Encana paid the consenting note holders an aggregate of approximately $792 million in cash reflecting a $768 million principal debt repayment, $2 million for the consent payment and $22 million of accrued and unpaid interest.
On April 28, 2014, pursuant to the Notice of Redemption issued on March 28, 2014, the Company redeemed the remaining principal amount of the
5.80 percent notes not tendered in the tender offer. Encana paid approximately $239 million in cash reflecting a $232 million principal debt repayment and $7 million of accrued and unpaid interest.
|
|
|
|
|
Notes to Condensed Consolidated Financial Statements
Prepared in accordance with U.S. GAAP in US$ |
Third quarter report
for the period ended September 30, 2015
Notes to Condensed
Consolidated Financial Statements (unaudited)
(All amounts in $ millions unless
otherwise specified)
|
11. Other Liabilities and Provisions |
|
|
|
|
|
|
|
|
|
|
|
As at September 30, 2015 |
|
|
As at December 31, 2014 |
|
|
|
|
The Bow Office Building (See Note 9) |
|
$ |
1,281 |
|
|
$ |
1,486 |
|
Capital Lease Obligations (See Note 9) |
|
|
378 |
|
|
|
473 |
|
Unrecognized Tax Benefits |
|
|
184 |
|
|
|
279 |
|
Pensions and Other Post-Employment Benefits |
|
|
158 |
|
|
|
144 |
|
Long-Term Incentives (See Note 18) |
|
|
23 |
|
|
|
70 |
|
Other |
|
|
43 |
|
|
|
32 |
|
|
|
$ |
2,067 |
|
|
$ |
2,484 |
|
The Bow Office Building
As
described in Note 9, Encana has recognized the accumulated costs for The Bow office building, which is under a 25-year lease agreement. At the conclusion of the 25-year term, the remaining asset and corresponding liability are expected to be
derecognized. Encana has also subleased part of The Bow office space to a subsidiary of Cenovus Energy Inc. (Cenovus). The total undiscounted future payments related to the lease agreement and the total undiscounted future amounts
expected to be recovered from the Cenovus sublease are outlined below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(undiscounted) |
|
2015 |
|
|
2016 |
|
|
2017 |
|
|
2018 |
|
|
2019 |
|
|
Thereafter |
|
|
Total |
|
|
|
|
|
|
|
|
|
Expected Future Lease Payments |
|
$ |
17 |
|
|
$ |
70 |
|
|
$ |
71 |
|
|
$ |
71 |
|
|
$ |
72 |
|
|
$ |
1,431 |
|
|
$ |
1,732 |
|
|
|
|
|
|
|
|
|
Sublease Recoveries |
|
$ |
(9) |
|
|
$ |
(34) |
|
|
$ |
(35) |
|
|
$ |
(35) |
|
|
$ |
(35) |
|
|
$ |
(703) |
|
|
$ |
(851 |
) |
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, equipment and an offshore production platform. Variable interests related to the PFC are described in Note 16.
The total expected future lease payments related to the Companys
capital lease obligations are outlined below. |
|
|
|
2015 |
|
|
2016 |
|
|
2017 |
|
|
2018 |
|
|
2019 |
|
|
Thereafter |
|
|
Total |
|
|
|
|
|
|
|
|
|
Expected Future Lease Payments |
|
$ |
24 |
|
|
$ |
98 |
|
|
$ |
99 |
|
|
$ |
99 |
|
|
$ |
99 |
|
|
$ |
232 |
|
|
$ |
651 |
|
Less Amounts Representing
Interest |
|
|
11 |
|
|
|
44 |
|
|
|
40 |
|
|
|
36 |
|
|
|
32 |
|
|
|
56 |
|
|
|
219 |
|
Present Value of Expected
Future Lease Payments |
|
$ |
13 |
|
|
$ |
54 |
|
|
$ |
59 |
|
|
$ |
63 |
|
|
$ |
67 |
|
|
$ |
176 |
|
|
$ |
432 |
|
|
|
|
Notes to Condensed Consolidated Financial Statements
Prepared in accordance with U.S. GAAP in US$ |
|
|
Third quarter report
for the period ended September 30, 2015
Notes to Condensed
Consolidated Financial Statements (unaudited)
(All amounts in $ millions unless
otherwise specified)
|
12. Asset Retirement Obligation |
|
|
|
|
|
|
|
|
|
As at September 30, 2015 |
|
|
As at
December 31, 2014 |
|
|
|
Asset Retirement Obligation, Beginning of Year |
|
$ |
913 |
|
|
$ 966 |
Liabilities Incurred and Acquired (See Note 4) |
|
|
15 |
|
|
85 |
Liabilities Settled and Divested |
|
|
(125) |
|
|
(188) |
Change in Estimated Future Cash Outflows |
|
|
- |
|
|
35 |
Accretion Expense |
|
|
34 |
|
|
52 |
Foreign Currency Translation |
|
|
(50) |
|
|
(37) |
Asset Retirement Obligation, End of Period |
|
$ |
787 |
|
|
$ 913 |
|
|
|
Current Portion |
|
$ |
30 |
|
|
$ 43 |
Long-Term Portion |
|
|
757 |
|
|
870 |
|
|
$ |
787 |
|
|
$ 913 |
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.
Issued and Outstanding
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As at
September 30, 2015 |
|
|
As at
December 31, 2014 |
|
|
|
Number (millions) |
|
|
Amount |
|
|
Number (millions) |
|
|
Amount |
|
|
|
|
|
|
Common Shares Outstanding, Beginning of Year |
|
|
741.2 |
|
|
$ |
2,450 |
|
|
|
740.9 |
|
|
$ |
2,445 |
|
Common Shares Issued |
|
|
98.4 |
|
|
|
1,098 |
|
|
|
- |
|
|
|
- |
|
Common Shares Issued Under Dividend Reinvestment Plan |
|
|
6.1 |
|
|
|
53 |
|
|
|
0.3 |
|
|
|
5 |
|
Common Shares Outstanding, End of Period |
|
|
845.7 |
|
|
$ |
3,601 |
|
|
|
741.2 |
|
|
$ |
2,450 |
|
On March 5, 2015, Encana filed a prospectus supplement (the Share Offering) to the Companys base
shelf prospectus for the issuance of 85,616,500 common shares and granted an over-allotment option for up to an additional 12,842,475 common shares at a price of C$14.60 per common share, pursuant to an underwriting agreement. The aggregate gross
proceeds from the Share Offering were approximately C$1.44 billion ($1.13 billion). After deducting underwriters fees and costs of the Share Offering, the net proceeds received were approximately C$1.39 billion ($1.09 billion).
During the nine months ended September 30, 2015, Encana issued 6,115,535 common shares totaling $53 million under the Companys dividend
reinvestment plan (DRIP). During the twelve months ended December 31, 2014, Encana issued 240,839 common shares totaling $5 million under the DRIP.
Dividends
During the three months ended September 30,
2015, Encana paid dividends of $0.07 per common share totaling $59 million (2014 - $0.07 per common share totaling $52 million). During the nine months ended September 30, 2015, Encana paid dividends of $0.21 per common share totaling $166
million (2014 - $0.21 per common share totaling $156 million). Common shares issued as part of the Share Offering as described above were not eligible to receive the dividend paid on March 31, 2015.
For the three and nine months ended September 30, 2015, the dividends paid included $21 million and $53 million, respectively, in common shares
issued in lieu of cash dividends under the DRIP (for the three and nine months ended September 30, 2014 - $1 million and $4 million, respectively).
|
|
|
|
|
Notes to Condensed Consolidated Financial Statements
Prepared in accordance with U.S. GAAP in US$ |
Third quarter report
for the period ended September 30, 2015
Notes to Condensed
Consolidated Financial Statements (unaudited)
(All amounts in $ millions unless
otherwise specified)
|
13. Share Capital (continued) |
Earnings Per Common Share
The following table presents the computation of net earnings per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
(millions, except per share amounts) |
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
Net Earnings (Loss) Attributable to Common Shareholders |
|
$ |
(1,236) |
|
|
$ |
2,807 |
|
|
$ |
(4,553) |
|
|
$ |
3,194 |
|
|
|
|
|
|
Number of Common Shares: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding - Basic |
|
|
843.1 |
|
|
|
741.1 |
|
|
|
814.0 |
|
|
|
741.0 |
|
Effect of dilutive securities |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Weighted average common shares outstanding - Diluted |
|
|
843.1 |
|
|
|
741.1 |
|
|
|
814.0 |
|
|
|
741.0 |
|
|
|
|
|
|
Net Earnings (Loss) per Common Share |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
(1.47) |
|
|
$ |
3.79 |
|
|
$ |
(5.59) |
|
|
$ |
4.31 |
|
Diluted |
|
$ |
(1.47) |
|
|
$ |
3.79 |
|
|
$ |
(5.59) |
|
|
$ |
4.31 |
|
Encana Stock Option Plan
Encana has share-based compensation plans that allow employees to purchase common shares of the Company. Option exercise prices are not less than the
market value of the common shares on the date the options are granted. All options outstanding as at September 30, 2015 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 Encanas 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, Encana does not consider
outstanding TSARs to be potentially dilutive securities.
Encana Restricted Share Units (RSUs)
Encana has a share-based compensation plan whereby eligible employees are granted RSUs. An RSU is a conditional grant to receive an Encana common share,
or the cash equivalent, as determined by Encana, upon vesting of the RSUs and in accordance with the terms of the RSU Plan and Grant Agreement. The Company intends to settle vested RSUs in cash on the vesting date. As a result, Encana does not
consider RSUs to be potentially dilutive securities.
|
|
|
Notes to Condensed Consolidated Financial Statements
Prepared in accordance with U.S. GAAP in US$ |
|
|
Third quarter report
for the period ended September 30, 2015
Notes to Condensed
Consolidated Financial Statements (unaudited)
(All amounts in $ millions unless
otherwise specified)
|
14. Accumulated Other Comprehensive Income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
September 30, |
|
|
Nine Months Ended
September 30, |
|
|
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
Foreign Currency Translation Adjustment |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, Beginning of Period |
|
$ |
1,140 |
|
|
$ |
715 |
|
|
$ |
715 |
|
|
$ |
693 |
|
Current Period Change in Foreign Currency Translation Adjustment |
|
|
175 |
|
|
|
(58) |
|
|
|
600 |
|
|
|
(36 |
) |
Balance, End of Period |
|
$ |
1,315 |
|
|
$ |
657 |
|
|
$ |
1,315 |
|
|
$ |
657 |
|
|
|
|
|
|
Pension and Other Post-Employment Benefit Plans |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, Beginning of Period |
|
$ |
(25) |
|
|
$ |
(9) |
|
|
$ |
(26) |
|
|
$ |
(9 |
) |
Reclassification of Net Actuarial (Gains) and
Losses to Net Earnings (See Note 19) |
|
|
1 |
|
|
|
- |
|
|
|
2 |
|
|
|
- |
|
Income Taxes |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Balance, End of Period |
|
$ |
(24) |
|
|
$ |
(9) |
|
|
$ |
(24) |
|
|
$ |
(9 |
) |
Total Accumulated Other Comprehensive Income |
|
$ |
1,291 |
|
|
$ |
648 |
|
|
$ |
1,291 |
|
|
$ |
648 |
|
|
15. Noncontrolling Interest |
Initial Public Offering of Common Shares of PrairieSky
On May 29, 2014, Encana completed an initial public offering (IPO) of 52.0 million common shares of PrairieSky at a price of
C$28.00 per common share for gross proceeds of approximately C$1.46 billion. On June 3, 2014, the over-allotment option granted to the underwriters to purchase up to an additional 7.8 million common shares was exercised in full for gross
proceeds of approximately C$218.4 million. Encana received aggregate gross proceeds from the IPO of approximately C$1.67 billion ($1.54 billion). Subsequent to the IPO, Encana owned 70.2 million common shares of PrairieSky, representing a 54
percent ownership interest. Accordingly, Encana consolidated 100 percent of the financial position and results of operations of PrairieSky and recognized a noncontrolling interest for the third party ownership.
The noncontrolling interest in the former consolidated subsidiary, PrairieSky, was reflected as a separate component in the Condensed Consolidated
Statement of Changes in Shareholders Equity for the nine months ended September 30, 2014. Encana recorded $117 million of the proceeds from the IPO as a noncontrolling interest and the remainder of the proceeds of $1,427 million, less
transaction costs of $81 million, was recognized as paid in surplus as at September 30, 2014.
Secondary Public Offering of Common Shares of PrairieSky
On September 26, 2014, Encana completed the secondary offering of 70.2 million common shares of PrairieSky at a price of C$36.50 per
common share, for aggregate gross proceeds to Encana of approximately C$2.6 billion. Following the completion of the secondary offering, Encana no longer held an interest in PrairieSky. As discussed in Note 5, the PrairieSky divestiture resulted in
a significant alteration between capitalized costs and proved reserves in the Canadian cost centre. Accordingly, Encana recognized a gain on the divestiture of approximately $2,095 million, which is included in the (gain) loss on divestitures in the
Companys Condensed Consolidated Statement of Earnings. In conjunction with the divestiture, Encana derecognized the carrying amount of the net assets of $258 million, including goodwill of $39 million, and the noncontrolling interest of $133
million.
Distributions to Noncontrolling Interest Owners
During the period from May 29, 2014 to September 25, 2014, PrairieSky paid dividends of C$0.3174 per common share totaling $38 million, of
which $18 million was attributable to the noncontrolling interest as presented in the Condensed Consolidated Statement of Changes in Shareholders Equity and Condensed Consolidated Statement of Cash Flows.
Net Earnings Attributable to Noncontrolling Interest
During
the period from May 29, 2014 to September 25, 2014, the Company held a noncontrolling interest in PrairieSky. Accordingly, Encana consolidated 100 percent of the financial position and results of operations of PrairieSky and recognized a
noncontrolling interest for third party ownership. For the three and nine months ended September 30, 2014, net earnings and comprehensive income of $24 million and $34 million, respectively, were attributable to the noncontrolling interest as
presented in the Condensed Consolidated Statement of Earnings and Condensed Consolidated Statement of Comprehensive Income.
|
|
|
|
|
Notes to Condensed Consolidated Financial Statements
Prepared in accordance with U.S. GAAP in US$ |
Third quarter report
for the period ended September 30, 2015
Notes to Condensed
Consolidated Financial Statements (unaudited)
(All amounts in $ millions unless
otherwise specified)
|
16. Variable Interest Entities |
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 as described in Note 9. Under the lease contract, Encana has a purchase option and the option to extend the lease for 12 one-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
VIEs 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. Encanas maximum
exposure is the expected lease payments over the initial contract term. As at September 30, 2015, Encanas capital lease obligation of $364 million ($462 million as at December 31, 2014) is related to the PFC.
Veresen Midstream Limited Partnership
On March 31,
2015, Encana, along with the Cutbank Ridge Partnership (CRP), entered into natural gas gathering and compression agreements with Veresen Midstream Limited Partnership (VMLP), under an initial term of 30 years with two
potential five-year renewal terms. As part of the agreement, VMLP agreed to undertake future expansion of midstream services if required by Encana and the CRP in support of the anticipated future development of the Montney play. In addition, VMLP
provides to Encana and the CRP natural gas gathering and processing under agreements that were contributed to VMLP by its partner Veresen Inc., and have remaining terms of 17 years and up to a potential maximum of 10 one-year renewal terms.
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 VMLPs 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 long-term service agreements which include: i) a take or pay for volumes committed to certain gathering and processing assets; ii) an operating fee of which a portion can be converted into a fixed fee once VMLP
assumes operatorship of certain compression assets; and iii) a potential payout of minimum costs associated with certain gathering and compression assets. 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 service 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
Encanas 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 $1,169 million as at September 30, 2015.
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 22 under Transportation and
Processing. The potential payout requirement is highly uncertain as the amount is contingent on future production estimates, pace of development and the amount of capacity contracted to third parties. As at September 30, 2015, accounts payable
and accrued liabilities included $1 million related to the take or pay commitment.
|
|
|
Notes to Condensed Consolidated Financial Statements
Prepared in accordance with U.S. GAAP in US$ |
|
|
Third quarter report
for the period ended September 30, 2015
Notes to Condensed
Consolidated Financial Statements (unaudited)
(All amounts in $ millions unless
otherwise specified)
|
17. Restructuring Charges |
In November 2013, Encana announced its plans to align the organizational structure in support of the Companys
strategy. Since the announcement, total restructuring charges primarily related to severance costs of $125 million, before tax, have been incurred, of which $2 million remains accrued as at September 30, 2015. For the nine months ended
September 30, 2015, $1 million in restructuring charges were incurred (2014 - $29 million).
During the second quarter of 2015, Encana revised
its plans to align the organizational structure in continued support of the Companys strategy. Additional transition and severance costs are expected to total approximately $59 million before tax. For the nine months ended September 30,
2015, costs of $58 million were incurred, of which $12 million remains accrued. The remaining transition and severance costs of approximately $1 million are expected to be incurred during the remainder of 2015.
Restructuring charges are included in administrative expense in the Condensed Consolidated Statement of Earnings.
Encana has a number of compensation arrangements under which the Company awards various types of long-term incentive
grants to eligible employees. These primarily include TSARs, Performance TSARs, SARs, Performance SARs, Performance Share Units (PSUs), Deferred Share Units (DSUs) and RSUs. These compensation arrangements are share-based.
Encana accounts for TSARs, Performance TSARs, SARs, Performance SARs, PSUs and RSUs held by Encana employees as cash-settled share-based payment
transactions and, accordingly, accrues compensation costs over the vesting period based on the fair value of the rights determined using the Black-Scholes-Merton and other fair value models.
As at September 30, 2015, the following weighted average assumptions were used to determine the fair value of the share units held by Encana
employees:
|
|
|
|
|
|
|
|
|
|
|
Encana US$ Share Units |
|
|
Encana C$ Share Units |
|
|
|
|
Risk Free Interest Rate |
|
|
0.51% |
|
|
|
0.51% |
|
Dividend Yield |
|
|
4.35% |
|
|
|
4.11% |
|
Expected Volatility Rate |
|
|
34.80% |
|
|
|
32.43% |
|
Expected Term |
|
|
1.6 yrs |
|
|
|
1.6 yrs |
|
Market Share Price |
|
|
US$6.44 |
|
|
|
C$8.59 |
|
|
|
|
|
|
Notes to Condensed Consolidated Financial Statements
Prepared in accordance with U.S. GAAP in US$ |
Third quarter report
for the period ended September 30, 2015
Notes to Condensed
Consolidated Financial Statements (unaudited)
(All amounts in $ millions unless
otherwise specified)
|
18. Compensation Plans (continued) |
The Company has recognized the following share-based compensation costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
|
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
Compensation Costs of Transactions Classified as Cash-Settled |
|
$ |
(31) |
|
|
$ |
(14) |
|
|
$ |
(24) |
|
|
$ |
115 |
|
Compensation Costs of Transactions Classified as Equity-Settled (1) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(1) |
|
Total Share-Based Compensation Costs |
|
|
(31) |
|
|
|
(14) |
|
|
|
(24) |
|
|
|
114 |
|
Less: Total Share-Based Compensation Costs Capitalized |
|
|
11 |
|
|
|
5 |
|
|
|
9 |
|
|
|
(41) |
|
Total Share-Based Compensation Expense |
|
$ |
(20) |
|
|
$ |
(9) |
|
|
$ |
(15) |
|
|
$ |
73 |
|
|
|
|
|
|
Recognized on the Condensed Consolidated Statement of Earnings in: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating expense |
|
$ |
(7) |
|
|
$ |
(5) |
|
|
$ |
(6) |
|
|
$ |
31 |
|
Administrative expense |
|
|
(13) |
|
|
|
(4) |
|
|
|
(9) |
|
|
|
42 |
|
|
|
$ |
(20) |
|
|
$ |
(9) |
|
|
$ |
(15) |
|
|
$ |
73 |
|
(1) |
RSUs may be settled in cash or equity as determined by Encana. The Companys decision to cash settle RSUs was made subsequent to the original grant date.
|
As at September 30, 2015, the liability for share-based payment transactions totaled $59 million ($99 million as at
December 31, 2014), of which $36 million ($29 million as at December 31, 2014) is recognized in accounts payable and accrued liabilities in the Condensed Consolidated Balance Sheet.
|
|
|
|
|
|
|
|
|
|
|
As at September 30, 2015 |
|
|
As at December 31, 2014 |
|
|
|
|
Liability for Cash-Settled Share-Based Payment Transactions: |
|
|
|
|
|
|
|
|
Unvested |
|
$ |
52 |
|
|
$ |
78 |
|
Vested |
|
|
7 |
|
|
|
21 |
|
|
|
$ |
59 |
|
|
$ |
99 |
|
The following units were granted primarily in conjunction with the Companys March annual long-term incentive award.
The TSARs and SARs were granted at the volume-weighted average trading price of Encanas common shares for the five days prior to the grant date.
|
|
|
|
|
Nine Months Ended September 30, 2015 (thousands of units) |
|
|
|
|
|
TSARs |
|
|
1,934 |
|
SARs |
|
|
1,444 |
|
PSUs |
|
|
2,370 |
|
DSUs |
|
|
172 |
|
RSUs |
|
|
6,807 |
|
|
|
|
Notes to Condensed Consolidated Financial Statements
Prepared in accordance with U.S. GAAP in US$ |
|
|
Third quarter report
for the period ended September 30, 2015
Notes to Condensed
Consolidated Financial Statements (unaudited)
(All amounts in $ millions unless
otherwise specified)
|
19. 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 nine months ended September 30 as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits |
|
|
OPEB |
|
|
Total |
|
|
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
|
|
Defined Benefit Plan Expense |
|
$ |
1 |
|
|
$ |
- |
|
|
$ |
11 |
|
|
$ |
9 |
|
|
$ |
12 |
|
|
$ |
9 |
|
Defined Contribution Plan Expense |
|
|
23 |
|
|
|
26 |
|
|
|
- |
|
|
|
- |
|
|
|
23 |
|
|
|
26 |
|
Total Benefit Plans Expense |
|
$ |
24 |
|
|
$ |
26 |
|
|
$ |
11 |
|
|
$ |
9 |
|
|
$ |
35 |
|
|
$ |
35 |
|
Of the total benefit plans expense, $28 million (2014 - $27 million) was included in operating expense and $7 million
(2014 - $8 million) was included in administrative expense.
The defined periodic pension and OPEB expense for the nine months ended
September 30 are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits |
|
|
OPEB |
|
|
Total |
|
|
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
|
|
Current Service Costs |
|
$ |
2 |
|
|
$ |
2 |
|
|
$ |
8 |
|
|
$ |
6 |
|
|
$ |
10 |
|
|
$ |
8 |
|
Interest Cost |
|
|
7 |
|
|
|
9 |
|
|
|
3 |
|
|
|
3 |
|
|
|
10 |
|
|
|
12 |
|
Expected Return On Plan Assets |
|
|
(10) |
|
|
|
(11) |
|
|
|
- |
|
|
|
- |
|
|
|
(10) |
|
|
|
(11) |
|
Amounts Reclassified From Accumulated Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive Income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization of net actuarial (gains) and losses |
|
|
2 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
2 |
|
|
|
- |
|
Total Defined Benefit Plan Expense |
|
$ |
1 |
|
|
$ |
- |
|
|
$ |
11 |
|
|
$ |
9 |
|
|
$ |
12 |
|
|
$ |
9 |
|
The amounts recognized in other comprehensive income for the nine months ended September 30 are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits |
|
|
OPEB |
|
|
Total |
|
|
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
|
|
Total Amounts Recognized in Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive (Income) Loss, Before Tax |
|
$ |
(2) |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
(2) |
|
|
$ |
- |
|
Total Amounts Recognized in Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive (Income) Loss, After Tax |
|
$ |
(2) |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
(2) |
|
|
$ |
- |
|
|
|
|
|
|
Notes to Condensed Consolidated Financial Statements
Prepared in accordance with U.S. GAAP in US$ |
Third quarter report
for the period ended September 30, 2015
Notes to Condensed
Consolidated Financial Statements (unaudited)
(All amounts in $ millions unless
otherwise specified)
|
20. Fair Value Measurements |
The fair values of cash and cash equivalents, accounts receivable and accrued revenues, and accounts payable and accrued
liabilities approximate their carrying amounts due to the short-term maturity of those instruments. The fair value of cash in reserve approximates its carrying amount due to the nature of the instrument held.
Recurring fair value measurements are performed for risk management assets and liabilities and are discussed further in Note 21. 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 tables below. There have been no transfers between the hierarchy levels during the period.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As at September 30, 2015 |
|
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 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk Management Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current |
|
$ |
- |
|
|
$ |
436 |
|
|
$ |
13 |
|
|
$ |
449 |
|
|
$ |
(22 |
) |
|
$ 427 |
Long-term |
|
|
- |
|
|
|
52 |
|
|
|
3 |
|
|
|
55 |
|
|
|
(4 |
) |
|
51 |
Risk Management Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current |
|
|
- |
|
|
|
22 |
|
|
|
10 |
|
|
|
32 |
|
|
|
(22 |
) |
|
10 |
Long-term |
|
|
- |
|
|
|
4 |
|
|
|
9 |
|
|
|
13 |
|
|
|
(4 |
) |
|
9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As at December 31, 2014 |
|
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 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk Management Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current |
|
$ |
- |
|
|
$ |
718 |
|
|
$ |
- |
|
|
$ |
718 |
|
|
$ |
(11 |
) |
|
$ 707 |
Long-term |
|
|
- |
|
|
|
67 |
|
|
|
- |
|
|
|
67 |
|
|
|
(2 |
) |
|
65 |
Risk Management Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current |
|
|
6 |
|
|
|
14 |
|
|
|
11 |
|
|
|
31 |
|
|
|
(11 |
) |
|
20 |
Long-term |
|
|
- |
|
|
|
2 |
|
|
|
7 |
|
|
|
9 |
|
|
|
(2 |
) |
|
7 |
(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. |
|
|
|
Notes to Condensed Consolidated Financial Statements
Prepared in accordance with U.S. GAAP in US$ |
|
|
Third quarter report
for the period ended September 30, 2015
Notes to Condensed
Consolidated Financial Statements (unaudited)
(All amounts in $ millions unless
otherwise specified)
|
20. Fair Value Measurements (continued) |
The Companys Level 1 and Level 2 risk management assets and liabilities consist of commodity
fixed price contracts, NYMEX three-way costless collars, WTI fixed price swaptions and basis swaps with terms as disclosed in Note 21. 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 September 30, 2015, the Companys Level 3 risk management assets and liabilities consist of power
purchase contracts with terms to 2017 and WTI three-way costless collars with terms to 2016. The fair values of the power purchase contracts are based on the income approach and are modelled internally using observable and unobservable inputs such
as forward power prices in less active markets. The WTI three-way costless collars are a combination of a sold call, purchased put and a sold 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 partial downside price protection through the combination of the put options. The fair values of the WTI three-way 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.
Changes in amounts related to risk management assets and liabilities are recognized in revenues and transportation and processing expense according to
their purpose.
A summary of changes in Level 3 fair value measurements for the nine months ended September 30 is presented below:
|
|
|
|
|
|
|
|
|
|
|
Risk Management |
|
|
|
2015 |
|
|
2014 |
|
|
|
|
Balance, Beginning of Year |
|
$ |
(18) |
|
|
$ |
(7) |
|
Total Gains (Losses) |
|
|
(12) |
|
|
|
(5) |
|
Purchases and Settlements: |
|
|
|
|
|
|
|
|
Purchases |
|
|
16 |
|
|
|
- |
|
Settlements |
|
|
11 |
|
|
|
5 |
|
Transfers in and out of Level 3 |
|
|
- |
|
|
|
- |
|
Balance, End of Period |
|
$ |
(3) |
|
|
$ |
(7) |
|
Change in unrealized gains (losses) related to assets and liabilities held at end of period
|
|
$ |
7 |
|
|
$ |
(2) |
|
Quantitative information about unobservable inputs used in Level 3 fair value measurements is presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Valuation Technique |
|
|
Unobservable Input |
|
As at
September 30, 2015 |
|
|
As at
December 31, 2014 |
|
Risk Management - Power |
|
|
Discounted Cash Flow |
|
|
Forward prices
($/Megawatt Hour) |
|
|
$36.17 - $42.00 |
|
|
|
$40.70 - $48.50 |
|
Risk Management - WTI Three-Way Costless Collars |
|
|
Option Model |
|
|
Implied Volatility |
|
|
31% - 42% |
|
|
|
- |
|
A 10 percent increase or decrease in estimated forward power prices would cause a corresponding $4 million ($5 million
as at December 31, 2014) increase or decrease to net risk management assets and liabilities. A 10 percent increase or decrease in implied volatility for the WTI three-way costless collars would cause a corresponding $3 million increase or
decrease to net risk management assets and liabilities (nil as at December 31, 2014).
|
|
|
|
|
Notes to Condensed Consolidated Financial Statements
Prepared in accordance with U.S. GAAP in US$ |
Third quarter report
for the period ended September 30, 2015
Notes to Condensed
Consolidated Financial Statements (unaudited)
(All amounts in $ millions unless
otherwise specified)
|
21. Financial Instruments and Risk Management |
A) Financial Instruments
Encanas financial assets and liabilities are recognized in cash and cash equivalents, accounts receivable and accrued revenues, cash in reserve,
accounts payable and accrued liabilities, risk management assets and liabilities and long-term debt.
B) Risk Management Assets and Liabilities
Risk management assets and liabilities arise from the use of derivative financial instruments and are measured at fair value. See Note 20 for a
discussion of fair value measurements.
|
|
|
|
|
|
|
|
|
Unrealized Risk Management Position |
|
As at September 30, 2015 |
|
|
As at December 31, 2014 |
|
|
|
|
Risk Management Assets |
|
|
|
|
|
|
|
|
Current |
|
$ |
427 |
|
|
$ |
707 |
|
Long-term |
|
|
51 |
|
|
|
65 |
|
|
|
|
478 |
|
|
|
772 |
|
|
|
|
Risk Management Liabilities |
|
|
|
|
|
|
|
|
Current |
|
|
10 |
|
|
|
20 |
|
Long-term |
|
|
9 |
|
|
|
7 |
|
|
|
|
19 |
|
|
|
27 |
|
Net Risk Management Assets |
|
$ |
459 |
|
|
$ |
745 |
|
Commodity Price Positions as at September 30, 2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Notional Volumes |
|
|
Term
|
|
Average Price |
|
|
|
|
Fair Value |
|
Natural Gas Contracts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed Price Contracts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NYMEX Fixed Price |
|
|
1,000 MMcf/d |
|
|
2015 |
|
|
4.29 US$/Mcf |
|
|
|
|
$ |
156 |
|
NYMEX Fixed Price |
|
|
95 MMcf/d |
|
|
2016 |
|
|
2.98 US$/Mcf |
|
|
|
|
|
6 |
|
NYMEX Three-Way Costless Collars |
|
|
300 MMcf/d |
|
|
2016 |
|
|
|
|
|
|
|
|
21 |
|
Sold call price |
|
|
|
|
|
|
|
|
3.43 US$/Mcf |
|
|
|
|
|
|
|
Bought put price |
|
|
|
|
|
|
|
|
3.21 US$/Mcf |
|
|
|
|
|
|
|
Sold put price |
|
|
|
|
|
|
|
|
2.72 US$/Mcf |
|
|
|
|
|
|
|
Basis Contracts (1) |
|
|
|
|
|
2015-2018 |
|
|
|
|
|
|
|
|
23 |
|
Other Financial Positions |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
- |
|
Natural Gas Fair Value Position |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
206 |
|
Crude Oil Contracts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed Price Contracts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WTI Fixed Price |
|
|
88.9 Mbbls/d |
|
|
2015 |
|
|
58.09 US$/bbl |
|
|
|
|
|
101 |
|
WTI Fixed Price |
|
|
38.0 Mbbls/d |
|
|
2016 |
|
|
62.83 US$/bbl |
|
|
|
|
|
187 |
|
WTI Fixed Price Swaptions (2) |
|
|
7.5 Mbbls/d |
|
|
2016 |
|
|
50.34 US$/bbl |
|
|
|
|
|
(7) |
|
WTI Three-Way Costless Collars |
|
|
18.3 Mbbls/d |
|
|
2016 |
|
|
|
|
|
|
|
|
16 |
|
Sold call price |
|
|
|
|
|
|
|
|
63.03 US$/bbl |
|
|
|
|
|
|
|
Bought put price |
|
|
|
|
|
|
|
|
55.00 US$/bbl |
|
|
|
|
|
|
|
Sold put price |
|
|
|
|
|
|
|
|
47.24 US$/bbl |
|
|
|
|
|
|
|
Basis Contracts (3) |
|
|
|
|
|
2015-2017 |
|
|
|
|
|
|
|
|
(25) |
|
Crude Oil Fair Value Position |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
272 |
|
Power Purchase Contracts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Position |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(19) |
|
Total Fair Value Position |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
459 |
|
(1) |
Encana has entered into swaps to protect against widening natural gas price differentials between benchmark and regional sales prices. These basis swaps are
priced using differentials determined as a percentage of NYMEX. |
(2) |
The WTI Fixed Price Swaptions give the counterparty the option to extend fourth quarter 2015 fixed price swaps to March 2016 at the same price.
|
(3) |
Encana has entered into swaps to protect against widening Brent and Midland differentials to WTI. These basis swaps are priced using fixed price
differentials. |
|
|
|
Notes to Condensed Consolidated Financial Statements
Prepared in accordance with U.S. GAAP in US$ |
|
|
Third quarter report
for the period ended September 30, 2015
Notes to Condensed
Consolidated Financial Statements (unaudited)
(All amounts in $ millions unless
otherwise specified)
|
21. Financial Instruments and Risk Management (continued) |
B) Risk Management Assets and Liabilities (continued)
Earnings Impact of Realized and Unrealized Gains (Losses) on Risk Management Positions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized Gain (Loss) |
|
|
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
|
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
Revenues, Net of Royalties |
|
$ |
217 |
|
|
$ |
29 |
|
|
$ |
626 |
|
|
$ |
(210) |
|
Transportation and Processing |
|
|
(4) |
|
|
|
(1) |
|
|
|
(12) |
|
|
|
(5) |
|
Gain (Loss) on Risk Management |
|
$ |
213 |
|
|
$ |
28 |
|
|
$ |
614 |
|
|
$ |
(215) |
|
|
|
|
|
Unrealized Gain (Loss) |
|
|
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
|
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
Revenues, Net of Royalties |
|
$ |
184 |
|
|
$ |
233 |
|
|
$ |
(237) |
|
|
$ |
(44) |
|
Transportation and Processing |
|
|
(11) |
|
|
|
(2) |
|
|
|
(4) |
|
|
|
(1) |
|
Gain (Loss) on Risk Management |
|
$ |
173 |
|
|
$ |
231 |
|
|
$ |
(241) |
|
|
$ |
(45) |
|
Reconciliation of Unrealized Risk Management Positions from January 1 to September 30
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2015 |
|
|
2014 |
|
|
|
Fair Value |
|
|
Total Unrealized Gain (Loss) |
|
|
Total Unrealized Gain (Loss) |
|
|
|
|
|
Fair Value of Contracts, Beginning of Year |
|
$ |
745 |
|
|
|
|
|
|
|
|
|
Change in Fair Value of Contracts in Place at Beginning of Year and Contracts Entered into During the Period |
|
|
373 |
|
|
$ |
373 |
|
|
$ |
(260) |
|
Foreign Exchange Translation Adjustment on Canadian Dollar Contracts |
|
|
2 |
|
|
|
|
|
|
|
|
|
Settlement of Athlon Crude Oil Contracts from Business Combination |
|
|
(47) |
|
|
|
|
|
|
|
|
|
Fair Value of Contracts Realized During the Period |
|
|
(614) |
|
|
|
(614) |
|
|
|
215 |
|
Fair Value of Contracts, End of Period |
|
$ |
459 |
|
|
$ |
(241) |
|
|
$ |
(45) |
|
C) Risks Associated with Financial Assets and Liabilities
The Company is exposed to financial risks including market risks (such as commodity prices, foreign exchange and interest rates), credit risk and
liquidity risk. Future cash flows may fluctuate due to movement in market prices and the exposure to credit and liquidity risks.
Commodity Price Risk
Commodity price risk arises from the effect 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 Companys
policy is to not use derivative financial instruments for speculative purposes.
Natural Gas - To partially mitigate natural gas commodity price
risk, the Company uses contracts such as NYMEX-based fixed price contracts, NYMEX-based options and costless collars. Encana also enters into basis swaps to manage against widening price differentials between various production areas and various
sales points.
Crude Oil - To partially mitigate crude oil commodity price risk, the Company uses contracts such as WTI-based fixed price contracts,
WTI-based options, swaptions and costless collars. Encana also enters into basis swaps to manage against widening price differentials between North American and world prices.
Power - The Company has entered into Canadian dollar denominated derivative contracts to manage its electricity consumption costs.
|
|
|
|
|
Notes to Condensed Consolidated Financial Statements
Prepared in accordance with U.S. GAAP in US$ |
Third quarter report
for the period ended September 30, 2015
Notes to Condensed
Consolidated Financial Statements (unaudited)
(All amounts in $ millions unless
otherwise specified)
|
21. Financial Instruments and Risk Management (continued) |
C) Risks Associated with Financial Assets and Liabilities (continued)
Commodity Price Risk (continued)
The table below summarizes the sensitivity of the fair value of the Companys 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) impacting pre-tax net earnings for the nine months ended September 30 as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2015 |
|
|
2014 |
|
|
|
10% Price Increase |
|
|
10% Price Decrease |
|
|
10% Price Increase |
|
|
10% Price Decrease |
|
|
|
|
|
|
Natural Gas Price |
|
$ |
(40) |
|
|
$ |
37 |
|
|
$ |
(197) |
|
|
$ |
197 |
|
Crude Oil Price |
|
|
(128) |
|
|
|
122 |
|
|
|
(24) |
|
|
|
24 |
|
Power Price |
|
|
4 |
|
|
|
(4) |
|
|
|
7 |
|
|
|
(7) |
|
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. This credit risk exposure is mitigated through the use of Board-approved credit
policies governing the Companys 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 at September 30, 2015, the Company
had no significant credit derivatives in place and no significant collateral balances were posted or received.
As at September 30, 2015, 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 in Canada and
the U.S. or with counterparties having investment grade credit ratings.
A substantial portion of the Companys accounts receivable are with
customers in the oil and gas industry and are subject to normal industry credit risks. As at September 30, 2015, approximately 93 percent (94 percent as at December 31, 2014) of Encanas accounts receivable and financial derivative
credit exposures were with investment grade counterparties.
As at September 30, 2015, Encana had two counterparties (three counterparties as at
December 31, 2014) whose net settlement position individually accounted for more than 10 percent of the fair value of the outstanding in-the-money net risk management contracts by counterparty. As at September 30, 2015, these
counterparties accounted for 10 percent and 10 percent (16 percent, 16 percent and 15 percent as at December 31, 2014) of the fair value of the outstanding in-the-money net risk management contracts.
Liquidity Risk
Liquidity risk arises from the potential that
the Company will encounter difficulties in meeting a demand to fund its financial liabilities as they come due. The Company manages liquidity risk using cash and debt management programs.
The Company has access to cash equivalents and a range of funding alternatives at competitive rates through committed revolving bank credit facilities
and debt and equity capital markets. As at September 30, 2015, the Company had committed revolving bank credit facilities totaling $4.5 billion which include $3.0 billion on a revolving bank credit facility for Encana and $1.5 billion on a
revolving bank credit facility for a U.S. subsidiary, the latter of which remains unused. The facilities remain committed through July 2020. Of the $3.0 billion revolving bank credit facility, $1.4 billion fully supported the U.S. Commercial Paper
Program and $1.6 billion remained unused.
Encana also has accessible capacity under a shelf prospectus for up to $4.9 billion, or the equivalent in
foreign currencies, the availability of which is dependent on market conditions, to issue debt and/or equity securities in Canada and/or the U.S. The shelf prospectus expires in July 2016.
The Company believes it has sufficient funding through the use of these facilities to meet foreseeable borrowing requirements.
|
|
|
Notes to Condensed Consolidated Financial Statements
Prepared in accordance with U.S. GAAP in US$ |
|
|
Third quarter report
for the period ended September 30, 2015
Notes to Condensed
Consolidated Financial Statements (unaudited)
(All amounts in $ millions unless
otherwise specified)
|
21. Financial Instruments and Risk Management (continued) |
C) Risks Associated with Financial Assets and Liabilities (continued)
Liquidity Risk (continued)
The Company minimizes its liquidity risk by managing its capital structure. The Companys capital
structure consists of shareholders equity plus long-term debt, including the current portion. The Companys objectives when managing its capital structure are to maintain financial flexibility to preserve Encanas access to capital
markets and its ability to meet financial obligations and to finance internally generated growth as well as potential acquisitions. To manage the capital structure, the Company may adjust capital spending, adjust dividends paid to shareholders,
issue new shares, issue new debt or repay existing debt.
The timing of expected cash outflows relating to financial liabilities is outlined in the
table below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Less Than
1 Year |
|
|
1 - 3 Years |
|
|
4 - 5 Years |
|
|
6 - 9 Years |
|
|
Thereafter |
|
|
Total |
|
|
|
|
|
|
|
|
Accounts Payable and Accrued Liabilities |
|
$ |
1,535 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
1,535 |
|
Risk Management Liabilities |
|
|
10 |
|
|
|
9 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
19 |
|
Long-Term Debt (1)
|
|
|
306 |
|
|
|
612 |
|
|
|
2,483 |
|
|
|
1,599 |
|
|
|
6,192 |
|
|
|
11,192 |
|
(1) |
Principal and interest. |
Included in
Encanas long-term debt obligations of $11,192 million at September 30, 2015 are $1,414 million in principal obligations for revolving credit and term loan borrowings related to U.S. Commercial Paper. These amounts are fully supported and
Management expects they will continue to be supported by revolving credit facilities that have no repayment requirements within the next year. The revolving credit facilities are fully revolving for a period of up to five years. Based on the current
maturity dates of the credit facilities, these amounts are included in cash outflows for the period disclosed as 4 - 5 Years. Further information on Long-Term Debt is contained in Note 10.
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 Companys financial assets or liabilities. As Encana operates primarily in North America, fluctuations in the exchange rate between the U.S. and
Canadian dollars can have a significant effect on the Companys reported results. Encanas financial results are consolidated in Canadian dollars; however, the Company reports its results in U.S. dollars as most of its revenue is closely
tied to the U.S. dollar and to facilitate a more direct comparison to other North American oil and gas companies. As the effects of foreign exchange fluctuations are embedded in the Companys results, the total effect of foreign exchange
fluctuations is not separately identifiable.
As at September 30, 2015, Encana had $6.1 billion in U.S. dollar debt issued from Canada that was
subject to foreign exchange exposure. As at December 31, 2014, Encana had $6.7 billion in debt that was subject to foreign exchange exposure and $0.6 billion that was not subject to foreign exchange exposure. To mitigate the exposure to the
fluctuating U.S./Canadian dollar exchange rate, Encana may enter into foreign exchange derivatives. There were no foreign exchange derivatives outstanding as at September 30, 2015.
Encanas foreign exchange (gain) loss primarily includes foreign exchange gains and losses on the translation and settlement of U.S. dollar
denominated debt issued from Canada, unrealized foreign exchange gains and losses on the translation of U.S. dollar denominated risk management assets and liabilities held in Canada, foreign exchange gains and losses on the translation and
settlement of foreign denominated intercompany balances and foreign exchange gains and losses on U.S. dollar denominated cash and short-term investments held in Canada. A $0.01 change in the U.S. to Canadian dollar exchange rate would have resulted
in a $47 million change in foreign exchange (gain) loss as at September 30, 2015 (2014 - $27 million).
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 Companys 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. There were no interest rate derivatives outstanding as at September 30, 2015.
As at September 30, 2015, the Company
had floating rate debt of $1,414 million. Accordingly, the sensitivity in net earnings for each one percent change in interest rates on floating rate debt was $10 million (2014 - nil).
|
|
|
|
|
Notes to Condensed Consolidated Financial Statements
Prepared in accordance with U.S. GAAP in US$ |
Third quarter report
for the period ended September 30, 2015
Notes to Condensed
Consolidated Financial Statements (unaudited)
(All amounts in $ millions unless
otherwise specified)
|
22. Commitments and Contingencies |
Commitments
The following
table outlines the Companys commitments as at September 30, 2015:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected Future Payments |
|
(undiscounted) |
|
2015 |
|
|
2016 |
|
|
2017 |
|
|
2018 |
|
|
2019 |
|
|
Thereafter |
|
|
Total |
|
|
|
|
|
|
|
|
|
Transportation and Processing |
|
$ |
210 |
|
|
$ |
795 |
|
|
$ |
778 |
|
|
$ |
790 |
|
|
$ |
672 |
|
|
$ |
3,037 |
|
|
$ |
6,282 |
|
Drilling and Field Services |
|
|
62 |
|
|
|
151 |
|
|
|
107 |
|
|
|
54 |
|
|
|
18 |
|
|
|
22 |
|
|
|
414 |
|
Operating Leases |
|
|
9 |
|
|
|
29 |
|
|
|
24 |
|
|
|
23 |
|
|
|
11 |
|
|
|
23 |
|
|
|
119 |
|
Total |
|
$ |
281 |
|
|
$ |
975 |
|
|
$ |
909 |
|
|
$ |
867 |
|
|
$ |
701 |
|
|
$ |
3,082 |
|
|
$ |
6,815 |
|
Included within transportation and processing in the table above are certain commitments associated with midstream
service agreements with VMLP as described in Note 16. Announced divestiture transactions can reduce certain commitments disclosed above.
Contingencies
Encana is involved in various legal claims and actions arising in the course of the Companys 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 Encanas financial position, cash flows or results of operations. If an unfavourable outcome were to occur, there exists the
possibility of a material adverse impact on the Companys consolidated net earnings or loss in the period in which the outcome is determined. Accruals for litigation and claims are recognized if the Company determines that the loss is probable
and the amount can be reasonably estimated. The Company believes it has made adequate provision for such legal claims.
On October 8, 2015, Encana announced an agreement to sell its DJ Basin assets in Colorado, for total consideration
of approximately $900 million. The transaction is expected to close in the fourth quarter of 2015, with an effective date of April 1, 2015, and is subject to satisfaction of normal closing conditions, regulatory approvals and other adjustments.
|
|
|
Notes to Condensed Consolidated Financial Statements
Prepared in accordance with U.S. GAAP in US$ |
|
|
|
|
|
|
|
Encana Corporation
Interim Supplemental Information
(unaudited)
For the period ended September 30, 2015
U.S. Dollars / U.S. Protocol
|
Third quarter report
for the period ended September 30, 2015
Supplemental
Financial Information (unaudited)
Financial Results
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2015 |
|
|
2014 |
|
($ millions, except per share amounts) |
|
Year-to-
date |
|
Q3 |
|
|
Q2 |
|
|
Q1 |
|
|
Year |
|
|
Q4 |
|
|
Q3 Year-
to-date |
|
Q3 |
|
|
Q2 |
|
|
Q1 |
|
Cash Flow (1) |
|
1,047 |
|
|
371 |
|
|
|
181 |
|
|
|
495 |
|
|
|
2,934 |
|
|
|
377 |
|
|
2,557 |
|
|
807 |
|
|
|
656 |
|
|
|
1,094 |
|
Per share - Diluted (4) |
|
1.29 |
|
|
0.44 |
|
|
|
0.22 |
|
|
|
0.65 |
|
|
|
3.96 |
|
|
|
0.51 |
|
|
3.45 |
|
|
1.09 |
|
|
|
0.89 |
|
|
|
1.48 |
|
|
|
|
|
|
|
|
|
|
|
|
Operating Earnings (Loss) (2,3) |
|
(172) |
|
|
(24 |
) |
|
|
(167 |
) |
|
|
19 |
|
|
|
1,002 |
|
|
|
35 |
|
|
967 |
|
|
281 |
|
|
|
171 |
|
|
|
515 |
|
Per share - Diluted (4) |
|
(0.21) |
|
|
(0.03 |
) |
|
|
(0.20 |
) |
|
|
0.03 |
|
|
|
1.35 |
|
|
|
0.05 |
|
|
1.30 |
|
|
0.38 |
|
|
|
0.23 |
|
|
|
0.70 |
|
|
|
|
|
|
|
|
|
|
|
|
Net Earnings (Loss) Attributable to Common Shareholders |
|
(4,553) |
|
|
(1,236 |
) |
|
|
(1,610 |
) |
|
|
(1,707 |
) |
|
|
3,392 |
|
|
|
198 |
|
|
3,194 |
|
|
2,807 |
|
|
|
271 |
|
|
|
116 |
|
Per share - Diluted (4) |
|
(5.59) |
|
|
(1.47 |
) |
|
|
(1.91 |
) |
|
|
(2.25 |
) |
|
|
4.58 |
|
|
|
0.27 |
|
|
4.31 |
|
|
3.79 |
|
|
|
0.37 |
|
|
|
0.16 |
|
|
|
|
|
|
|
|
|
|
|
|
Effective Tax Rate using Canadian Statutory Rate |
|
26.4% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
25.7% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign Exchange Rates (US$ per C$1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average |
|
0.794 |
|
|
0.764 |
|
|
|
0.813 |
|
|
|
0.806 |
|
|
|
0.905 |
|
|
|
0.881 |
|
|
0.914 |
|
|
0.918 |
|
|
|
0.917 |
|
|
|
0.906 |
|
Period end |
|
0.747 |
|
|
0.747 |
|
|
|
0.802 |
|
|
|
0.789 |
|
|
|
0.862 |
|
|
|
0.862 |
|
|
0.892 |
|
|
0.892 |
|
|
|
0.937 |
|
|
|
0.905 |
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flow Summary |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash From (Used in) Operating Activities |
|
1,233 |
|
|
453 |
|
|
|
298 |
|
|
|
482 |
|
|
|
2,667 |
|
|
|
261 |
|
|
2,406 |
|
|
696 |
|
|
|
767 |
|
|
|
943 |
|
Deduct (Add back): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net change in other assets and liabilities
|
|
(18) |
|
|
(18 |
) |
|
|
7 |
|
|
|
(7 |
) |
|
|
(43) |
|
|
|
(15 |
) |
|
(28) |
|
|
(11 |
) |
|
|
(8 |
) |
|
|
(9) |
|
Net change in non-cash working capital
|
|
204 |
|
|
100 |
|
|
|
110 |
|
|
|
(6 |
) |
|
|
(9) |
|
|
|
(141 |
) |
|
132 |
|
|
155 |
|
|
|
119 |
|
|
|
(142) |
|
Cash tax on sale of assets |
|
- |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(215) |
|
|
|
40 |
|
|
(255) |
|
|
(255 |
) |
|
|
- |
|
|
|
- |
|
Cash Flow (1) |
|
1,047 |
|
|
371 |
|
|
|
181 |
|
|
|
495 |
|
|
|
2,934 |
|
|
|
377 |
|
|
2,557 |
|
|
807 |
|
|
|
656 |
|
|
|
1,094 |
|
|
|
|
|
|
|
|
|
|
|
|
Operating Earnings Summary |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Earnings (Loss) Attributable to Common Shareholders |
|
(4,553) |
|
|
(1,236 |
) |
|
|
(1,610 |
) |
|
|
(1,707 |
) |
|
|
3,392 |
|
|
|
198 |
|
|
3,194 |
|
|
2,807 |
|
|
|
271 |
|
|
|
116 |
|
After-tax (addition) deduction: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized hedging gain (loss) |
|
(178) |
|
|
107 |
|
|
|
(187 |
) |
|
|
(98 |
) |
|
|
306 |
|
|
|
341 |
|
|
(35) |
|
|
160 |
|
|
|
8 |
|
|
|
(203) |
|
Impairments |
|
(3,616) |
|
|
(1,066 |
) |
|
|
(1,328 |
) |
|
|
(1,222 |
) |
|
|
- |
|
|
|
- |
|
|
- |
|
|
- |
|
|
|
- |
|
|
|
- |
|
Restructuring charges (3) |
|
(40) |
|
|
(20 |
) |
|
|
(10 |
) |
|
|
(10 |
) |
|
|
(24) |
|
|
|
(4 |
) |
|
(20) |
|
|
(5 |
) |
|
|
(5 |
) |
|
|
(10) |
|
Non-operating foreign exchange gain
(loss) |
|
(606) |
|
|
(212 |
) |
|
|
114 |
|
|
|
(508 |
) |
|
|
(407) |
|
|
|
(151 |
) |
|
(256) |
|
|
(218 |
) |
|
|
156 |
|
|
|
(194) |
|
Gain (loss) on divestitures |
|
9 |
|
|
(2 |
) |
|
|
1 |
|
|
|
10 |
|
|
|
2,523 |
|
|
|
(11 |
) |
|
2,534 |
|
|
2,399 |
|
|
|
135 |
|
|
|
- |
|
Income tax adjustments |
|
50 |
|
|
(19 |
) |
|
|
(33 |
) |
|
|
102 |
|
|
|
(8) |
|
|
|
(12 |
) |
|
4 |
|
|
190 |
|
|
|
(194 |
) |
|
|
8 |
|
Operating Earnings (Loss) (2,3) |
|
(172) |
|
|
(24 |
) |
|
|
(167 |
) |
|
|
19 |
|
|
|
1,002 |
|
|
|
35 |
|
|
967 |
|
|
281 |
|
|
|
171 |
|
|
|
515 |
|
(1) |
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 cash tax on sale of assets. |
(2) |
Operating Earnings (Loss) is a non-GAAP measure defined as net earnings (loss) attributable to common shareholders excluding non-recurring or non-cash items
that Management believes reduces the comparability of the Companys financial performance between periods. These after-tax items may include, but are not limited to, unrealized hedging gains/losses, impairments, restructuring charges,
non-operating foreign exchange gains/losses, gains/losses on divestitures, income taxes related to divestitures and adjustments to normalize the effect of income taxes calculated using the estimated annual effective income tax rate.
|
(3) |
In continued support of Encanas strategy, organizational structure changes were formalized in Q2 2015 and resulted in a revision to the Q1 2015
Operating Earnings to exclude restructuring charges incurred in the first quarter. |
(4) |
Net earnings (loss) attributable to common shareholders, operating earnings (loss) and cash flow per common share are calculated using the weighted average
number of Encana common shares outstanding as follows: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2015 |
|
|
2014 |
|
(millions) |
|
Year-to-
date |
|
Q3 |
|
|
Q2 |
|
|
Q1 |
|
|
Year |
|
|
Q4 |
|
|
Q3 Year-
to-date |
|
Q3 |
|
|
Q2 |
|
|
Q1 |
|
Weighted Average Common Shares Outstanding
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
814.0 |
|
|
843.1 |
|
|
|
841.2 |
|
|
|
757.8 |
|
|
|
741.0 |
|
|
|
741.1 |
|
|
741.0 |
|
|
741.1 |
|
|
|
741.0 |
|
|
|
741.0 |
|
Diluted |
|
814.0 |
|
|
843.1 |
|
|
|
841.2 |
|
|
|
757.8 |
|
|
|
741.0 |
|
|
|
741.1 |
|
|
741.0 |
|
|
741.1 |
|
|
|
741.0 |
|
|
|
741.0 |
|
|
|
|
Supplemental Information
Prepared in US$ |
|
|
Third quarter report
for the period ended September 30, 2015
Supplemental Financial & Operating Information (unaudited)
Financial Metrics
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2015 |
|
|
|
|
|
|
|
|
|
|
2014 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year-to-
date |
|
|
|
|
|
|
|
|
|
|
Year |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Debt to Debt Adjusted Cash Flow |
|
3.1x |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2.1x |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Debt to Adjusted Capitalization |
|
30% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
30% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The financial metrics disclosed above are non-GAAP measures monitored by Management as indicators of the Companys overall financial strength. These
non-GAAP measures are defined and calculated in the Non-GAAP Measures section of Encanas Managements Discussion and Analysis. |
|
|
Net Capital Investment |
|
|
|
2015 |
|
|
2014 |
|
($ millions) |
|
Year-to-
date |
|
Q3 |
|
|
Q2 |
|
|
Q1 |
|
|
Year |
|
|
Q4 |
|
|
Q3 Year-
to-date |
|
Q3 |
|
|
Q2 |
|
|
Q1 |
|
Capital Investment |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
341 |
|
|
76 |
|
|
|
114 |
|
|
|
151 |
|
|
|
1,226 |
|
|
|
302 |
|
|
924 |
|
|
293 |
|
|
|
350 |
|
|
|
281 |
|
USA Operations |
|
1,605 |
|
|
394 |
|
|
|
628 |
|
|
|
583 |
|
|
|
1,285 |
|
|
|
548 |
|
|
737 |
|
|
305 |
|
|
|
206 |
|
|
|
226 |
|
Market Optimization |
|
1 |
|
|
1 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
- |
|
|
(2 |
) |
|
|
1 |
|
|
|
1 |
|
Corporate & Other |
|
5 |
|
|
2 |
|
|
|
1 |
|
|
|
2 |
|
|
|
15 |
|
|
|
7 |
|
|
8 |
|
|
2 |
|
|
|
3 |
|
|
|
3 |
|
Capital Investment |
|
1,952 |
|
|
473 |
|
|
|
743 |
|
|
|
736 |
|
|
|
2,526 |
|
|
|
857 |
|
|
1,669 |
|
|
598 |
|
|
|
560 |
|
|
|
511 |
|
Net Acquisitions & (Divestitures) |
|
(1,077) |
|
|
(99 |
) |
|
|
(140 |
) |
|
|
(838 |
) |
|
|
(1,329 |
) |
|
|
50 |
|
|
(1,379) |
|
|
(2,007 |
) |
|
|
652 |
|
|
|
(24) |
|
Net Capital Investment |
|
875 |
|
|
374 |
|
|
|
603 |
|
|
|
(102 |
) |
|
|
1,197 |
|
|
|
907 |
|
|
290 |
|
|
(1,409 |
) |
|
|
1,212 |
|
|
|
487 |
|
|
Capital Investment |
|
|
|
2015 |
|
|
2014 |
|
($ millions) |
|
Year-to-
date |
|
Q3 |
|
|
Q2 |
|
|
Q1 |
|
|
Year |
|
|
Q4 |
|
|
Q3 Year-
to-date |
|
Q3 |
|
|
Q2 |
|
|
Q1 |
|
Capital Investment |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Montney (1) |
|
144 |
|
|
17 |
|
|
|
48 |
|
|
|
79 |
|
|
|
781 |
|
|
|
159 |
|
|
622 |
|
|
204 |
|
|
|
210 |
|
|
|
208 |
|
Duvernay |
|
185 |
|
|
58 |
|
|
|
57 |
|
|
|
70 |
|
|
|
328 |
|
|
|
118 |
|
|
210 |
|
|
58 |
|
|
|
81 |
|
|
|
71 |
|
Eagle Ford |
|
514 |
|
|
142 |
|
|
|
175 |
|
|
|
197 |
|
|
|
274 |
|
|
|
149 |
|
|
125 |
|
|
113 |
|
|
|
12 |
|
|
|
- |
|
Permian |
|
761 |
|
|
219 |
|
|
|
325 |
|
|
|
217 |
|
|
|
117 |
|
|
|
117 |
|
|
- |
|
|
- |
|
|
|
- |
|
|
|
- |
|
DJ Basin |
|
161 |
|
|
17 |
|
|
|
56 |
|
|
|
88 |
|
|
|
277 |
|
|
|
81 |
|
|
196 |
|
|
68 |
|
|
|
69 |
|
|
|
59 |
|
San Juan |
|
61 |
|
|
2 |
|
|
|
23 |
|
|
|
36 |
|
|
|
287 |
|
|
|
96 |
|
|
191 |
|
|
89 |
|
|
|
50 |
|
|
|
52 |
|
|
|
1,826 |
|
|
455 |
|
|
|
684 |
|
|
|
687 |
|
|
|
2,064 |
|
|
|
720 |
|
|
1,344 |
|
|
532 |
|
|
|
422 |
|
|
|
390 |
|
Other Upstream Operations (1, 2) |
|
120 |
|
|
15 |
|
|
|
58 |
|
|
|
47 |
|
|
|
447 |
|
|
|
130 |
|
|
317 |
|
|
66 |
|
|
|
134 |
|
|
|
117 |
|
Market Optimization |
|
1 |
|
|
1 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
- |
|
|
(2 |
) |
|
|
1 |
|
|
|
1 |
|
Corporate & Other |
|
5 |
|
|
2 |
|
|
|
1 |
|
|
|
2 |
|
|
|
15 |
|
|
|
7 |
|
|
8 |
|
|
2 |
|
|
|
3 |
|
|
|
3 |
|
Capital Investment |
|
1,952 |
|
|
473 |
|
|
|
743 |
|
|
|
736 |
|
|
|
2,526 |
|
|
|
857 |
|
|
1,669 |
|
|
598 |
|
|
|
560 |
|
|
|
511 |
|
(1) |
Montney has been realigned to include certain capital investments which were previously reported in Other Upstream Operations. |
(2) |
Other Upstream Operations includes capital investment for Encanas base production properties as well as capital investment for prospective plays which
are under appraisal, including the Tuscaloosa Marine Shale (TMS). |
|
|
|
|
|
Supplemental Information Prepared in US$ |
Third quarter report
for the period ended September 30, 2015
Supplemental Financial & Operating Information (unaudited)
Production Volumes - After Royalties
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2015 |
|
|
2014 |
|
(average) |
|
Year-to-
date |
|
Q3 |
|
|
Q2 |
|
|
Q1 |
|
|
Year |
|
|
Q4 |
|
|
Q3 Year-
to-date |
|
Q3 |
|
|
Q2 |
|
|
Q1 |
|
Natural Gas (MMcf/d) |
|
1,656 |
|
|
1,547 |
|
|
|
1,568 |
|
|
|
1,857 |
|
|
|
2,350 |
|
|
|
1,861 |
|
|
2,515 |
|
|
2,199 |
|
|
|
2,541 |
|
|
|
2,809 |
|
Oil (Mbbls/d) |
|
85.8 |
|
|
91.9 |
|
|
|
86.2 |
|
|
|
79.2 |
|
|
|
49.4 |
|
|
|
68.8 |
|
|
42.9 |
|
|
62.1 |
|
|
|
34.2 |
|
|
|
32.1 |
|
NGLs (Mbbls/d) |
|
43.7 |
|
|
48.5 |
|
|
|
41.1 |
|
|
|
41.5 |
|
|
|
37.4 |
|
|
|
37.6 |
|
|
37.3 |
|
|
41.9 |
|
|
|
34.0 |
|
|
|
35.8 |
|
Oil & NGLs (Mbbls/d) |
|
129.5 |
|
|
140.4 |
|
|
|
127.3 |
|
|
|
120.7 |
|
|
|
86.8 |
|
|
|
106.4 |
|
|
80.2 |
|
|
104.0 |
|
|
|
68.2 |
|
|
|
67.9 |
|
Total (MBOE/d) |
|
405.6 |
|
|
398.3 |
|
|
|
388.7 |
|
|
|
430.1 |
|
|
|
478.5 |
|
|
|
416.7 |
|
|
499.3 |
|
|
470.6 |
|
|
|
491.8 |
|
|
|
536.1 |
|
Production Volumes - After Royalties
|
|
|
|
2015 |
|
|
2014 |
|
(average) |
|
Year-to-
date |
|
Q3 |
|
|
Q2 |
|
|
Q1 |
|
|
Year |
|
|
Q4 |
|
|
Q3 Year-
to-date |
|
Q3 |
|
|
Q2 |
|
|
Q1 |
|
Natural Gas (MMcf/d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
961 |
|
|
876 |
|
|
|
881 |
|
|
|
1,128 |
|
|
|
1,378 |
|
|
|
1,111 |
|
|
1,468 |
|
|
1,374 |
|
|
|
1,463 |
|
|
|
1,568 |
|
USA Operations |
|
695 |
|
|
671 |
|
|
|
687 |
|
|
|
729 |
|
|
|
972 |
|
|
|
750 |
|
|
1,047 |
|
|
825 |
|
|
|
1,078 |
|
|
|
1,241 |
|
|
|
1,656 |
|
|
1,547 |
|
|
|
1,568 |
|
|
|
1,857 |
|
|
|
2,350 |
|
|
|
1,861 |
|
|
2,515 |
|
|
2,199 |
|
|
|
2,541 |
|
|
|
2,809 |
|
Oil (Mbbls/d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
6.1 |
|
|
5.3 |
|
|
|
6.5 |
|
|
|
6.6 |
|
|
|
13.6 |
|
|
|
9.4 |
|
|
15.0 |
|
|
14.7 |
|
|
|
13.9 |
|
|
|
16.4 |
|
USA Operations |
|
79.7 |
|
|
86.6 |
|
|
|
79.7 |
|
|
|
72.6 |
|
|
|
35.8 |
|
|
|
59.4 |
|
|
27.9 |
|
|
47.4 |
|
|
|
20.3 |
|
|
|
15.7 |
|
|
|
85.8 |
|
|
91.9 |
|
|
|
86.2 |
|
|
|
79.2 |
|
|
|
49.4 |
|
|
|
68.8 |
|
|
42.9 |
|
|
62.1 |
|
|
|
34.2 |
|
|
|
32.1 |
|
NGLs (Mbbls/d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
21.0 |
|
|
21.9 |
|
|
|
19.8 |
|
|
|
21.2 |
|
|
|
23.6 |
|
|
|
18.8 |
|
|
25.3 |
|
|
27.6 |
|
|
|
23.5 |
|
|
|
24.6 |
|
USA Operations |
|
22.7 |
|
|
26.6 |
|
|
|
21.3 |
|
|
|
20.3 |
|
|
|
13.8 |
|
|
|
18.8 |
|
|
12.0 |
|
|
14.3 |
|
|
|
10.5 |
|
|
|
11.2 |
|
|
|
43.7 |
|
|
48.5 |
|
|
|
41.1 |
|
|
|
41.5 |
|
|
|
37.4 |
|
|
|
37.6 |
|
|
37.3 |
|
|
41.9 |
|
|
|
34.0 |
|
|
|
35.8 |
|
Oil & NGLs (Mbbls/d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
27.1 |
|
|
27.2 |
|
|
|
26.3 |
|
|
|
27.8 |
|
|
|
37.2 |
|
|
|
28.2 |
|
|
40.3 |
|
|
42.3 |
|
|
|
37.4 |
|
|
|
41.0 |
|
USA Operations |
|
102.4 |
|
|
113.2 |
|
|
|
101.0 |
|
|
|
92.9 |
|
|
|
49.6 |
|
|
|
78.2 |
|
|
39.9 |
|
|
61.7 |
|
|
|
30.8 |
|
|
|
26.9 |
|
|
|
129.5 |
|
|
140.4 |
|
|
|
127.3 |
|
|
|
120.7 |
|
|
|
86.8 |
|
|
|
106.4 |
|
|
80.2 |
|
|
104.0 |
|
|
|
68.2 |
|
|
|
67.9 |
|
Total (MBOE/d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
187.2 |
|
|
173.2 |
|
|
|
173.2 |
|
|
|
215.8 |
|
|
|
266.9 |
|
|
|
213.4 |
|
|
285.0 |
|
|
271.4 |
|
|
|
281.4 |
|
|
|
302.4 |
|
USA Operations |
|
218.4 |
|
|
225.1 |
|
|
|
215.5 |
|
|
|
214.3 |
|
|
|
211.6 |
|
|
|
203.3 |
|
|
214.3 |
|
|
199.2 |
|
|
|
210.4 |
|
|
|
233.7 |
|
|
|
405.6 |
|
|
398.3 |
|
|
|
388.7 |
|
|
|
430.1 |
|
|
|
478.5 |
|
|
|
416.7 |
|
|
499.3 |
|
|
470.6 |
|
|
|
491.8 |
|
|
|
536.1 |
|
Oil & NGLs Production Volumes - After Royalties
|
|
|
|
2015 |
|
|
|
|
|
|
|
|
2014 |
|
|
|
|
|
|
|
|
|
|
|
|
(average Mbbls/d) |
|
Year-to-
date |
|
% of
Total |
|
|
|
|
|
|
|
|
Year |
|
|
%
of Total |
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
85.8 |
|
|
66 |
|
|
|
|
|
|
|
|
|
|
|
49.4 |
|
|
|
57 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Plant Condensate |
|
14.9 |
|
|
12 |
|
|
|
|
|
|
|
|
|
|
|
12.0 |
|
|
|
14 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Butane |
|
7.1 |
|
|
5 |
|
|
|
|
|
|
|
|
|
|
|
6.8 |
|
|
|
8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Propane |
|
11.9 |
|
|
9 |
|
|
|
|
|
|
|
|
|
|
|
10.2 |
|
|
|
11 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ethane |
|
9.8 |
|
|
8 |
|
|
|
|
|
|
|
|
|
|
|
8.4 |
|
|
|
10 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
129.5 |
|
|
100 |
|
|
|
|
|
|
|
|
|
|
|
86.8 |
|
|
|
100 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental Information
Prepared in US$ |
|
|
Third quarter report
for the period ended September 30, 2015
Supplemental Financial & Operating Information (unaudited)
Results of Operations
Product and Operational Information, Including the Impact of Realized Financial Hedging
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2015 |
|
|
2014 |
|
($ millions) |
|
Year-to-
date |
|
Q3 |
|
|
Q2 |
|
|
Q1 |
|
|
Year |
|
|
Q4 |
|
|
Q3 Year-
to-date |
|
Q3 |
|
|
Q2 |
|
|
Q1 |
|
Natural Gas - Canadian Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues, Net of Royalties, excluding
Hedging |
|
788 |
|
|
199 |
|
|
|
193 |
|
|
|
396 |
|
|
|
2,468 |
|
|
|
402 |
|
|
2,066 |
|
|
480 |
|
|
|
569 |
|
|
|
1,017 |
|
Realized Financial Hedging Gain
(Loss) |
|
364 |
|
|
104 |
|
|
|
106 |
|
|
|
154 |
|
|
|
(74 |
) |
|
|
25 |
|
|
(99) |
|
|
20 |
|
|
|
(44 |
) |
|
|
(75) |
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and mineral taxes |
|
- |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
5 |
|
|
|
2 |
|
|
3 |
|
|
1 |
|
|
|
- |
|
|
|
2 |
|
Transportation and processing |
|
463 |
|
|
142 |
|
|
|
158 |
|
|
|
163 |
|
|
|
773 |
|
|
|
177 |
|
|
596 |
|
|
186 |
|
|
|
209 |
|
|
|
201 |
|
Operating |
|
111 |
|
|
35 |
|
|
|
40 |
|
|
|
36 |
|
|
|
279 |
|
|
|
57 |
|
|
222 |
|
|
66 |
|
|
|
72 |
|
|
|
84 |
|
Operating Cash Flow |
|
578 |
|
|
126 |
|
|
|
101 |
|
|
|
351 |
|
|
|
1,337 |
|
|
|
191 |
|
|
1,146 |
|
|
247 |
|
|
|
244 |
|
|
|
655 |
|
Natural Gas - USA Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues, Net of Royalties, excluding
Hedging |
|
511 |
|
|
170 |
|
|
|
146 |
|
|
|
195 |
|
|
|
1,640 |
|
|
|
274 |
|
|
1,366 |
|
|
307 |
|
|
|
463 |
|
|
|
596 |
|
Realized Financial Hedging Gain
(Loss) |
|
166 |
|
|
54 |
|
|
|
58 |
|
|
|
54 |
|
|
|
(85 |
) |
|
|
13 |
|
|
(98) |
|
|
10 |
|
|
|
(43 |
) |
|
|
(65) |
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and mineral taxes |
|
15 |
|
|
6 |
|
|
|
5 |
|
|
|
4 |
|
|
|
44 |
|
|
|
11 |
|
|
33 |
|
|
(10 |
) |
|
|
14 |
|
|
|
29 |
|
Transportation and processing |
|
445 |
|
|
152 |
|
|
|
142 |
|
|
|
151 |
|
|
|
651 |
|
|
|
149 |
|
|
502 |
|
|
162 |
|
|
|
177 |
|
|
|
163 |
|
Operating |
|
134 |
|
|
39 |
|
|
|
46 |
|
|
|
49 |
|
|
|
235 |
|
|
|
52 |
|
|
183 |
|
|
50 |
|
|
|
65 |
|
|
|
68 |
|
Operating Cash Flow |
|
83 |
|
|
27 |
|
|
|
11 |
|
|
|
45 |
|
|
|
625 |
|
|
|
75 |
|
|
550 |
|
|
115 |
|
|
|
164 |
|
|
|
271 |
|
Natural Gas - Total Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues, Net of Royalties, excluding
Hedging |
|
1,299 |
|
|
369 |
|
|
|
339 |
|
|
|
591 |
|
|
|
4,108 |
|
|
|
676 |
|
|
3,432 |
|
|
787 |
|
|
|
1,032 |
|
|
|
1,613 |
|
Realized Financial Hedging Gain
(Loss) |
|
530 |
|
|
158 |
|
|
|
164 |
|
|
|
208 |
|
|
|
(159 |
) |
|
|
38 |
|
|
(197) |
|
|
30 |
|
|
|
(87 |
) |
|
|
(140) |
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and mineral taxes |
|
15 |
|
|
6 |
|
|
|
5 |
|
|
|
4 |
|
|
|
49 |
|
|
|
13 |
|
|
36 |
|
|
(9 |
) |
|
|
14 |
|
|
|
31 |
|
Transportation and processing |
|
908 |
|
|
294 |
|
|
|
300 |
|
|
|
314 |
|
|
|
1,424 |
|
|
|
326 |
|
|
1,098 |
|
|
348 |
|
|
|
386 |
|
|
|
364 |
|
Operating |
|
245 |
|
|
74 |
|
|
|
86 |
|
|
|
85 |
|
|
|
514 |
|
|
|
109 |
|
|
405 |
|
|
116 |
|
|
|
137 |
|
|
|
152 |
|
Operating Cash Flow |
|
661 |
|
|
153 |
|
|
|
112 |
|
|
|
396 |
|
|
|
1,962 |
|
|
|
266 |
|
|
1,696 |
|
|
362 |
|
|
|
408 |
|
|
|
926 |
|
Oil & NGLs - Canadian
Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues, Net of Royalties, excluding
Hedging |
|
243 |
|
|
75 |
|
|
|
91 |
|
|
|
77 |
|
|
|
872 |
|
|
|
149 |
|
|
723 |
|
|
251 |
|
|
|
227 |
|
|
|
245 |
|
Realized Financial Hedging Gain
(Loss) |
|
2 |
|
|
5 |
|
|
|
(5 |
) |
|
|
2 |
|
|
|
18 |
|
|
|
24 |
|
|
(6) |
|
|
(1 |
) |
|
|
(5 |
) |
|
|
- |
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and mineral taxes |
|
- |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
10 |
|
|
|
- |
|
|
10 |
|
|
3 |
|
|
|
4 |
|
|
|
3 |
|
Transportation and processing |
|
38 |
|
|
11 |
|
|
|
13 |
|
|
|
14 |
|
|
|
62 |
|
|
|
16 |
|
|
46 |
|
|
16 |
|
|
|
16 |
|
|
|
14 |
|
Operating |
|
13 |
|
|
2 |
|
|
|
5 |
|
|
|
6 |
|
|
|
28 |
|
|
|
10 |
|
|
18 |
|
|
8 |
|
|
|
4 |
|
|
|
6 |
|
Operating Cash Flow |
|
194 |
|
|
67 |
|
|
|
68 |
|
|
|
59 |
|
|
|
790 |
|
|
|
147 |
|
|
643 |
|
|
223 |
|
|
|
198 |
|
|
|
222 |
|
Oil & NGLs - USA
Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues, Net of Royalties, excluding
Hedging |
|
1,080 |
|
|
371 |
|
|
|
414 |
|
|
|
295 |
|
|
|
1,258 |
|
|
|
412 |
|
|
846 |
|
|
452 |
|
|
|
215 |
|
|
|
179 |
|
Realized Financial Hedging Gain
(Loss) |
|
97 |
|
|
54 |
|
|
|
5 |
|
|
|
38 |
|
|
|
60 |
|
|
|
65 |
|
|
(5) |
|
|
1 |
|
|
|
(6 |
) |
|
|
- |
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and mineral taxes |
|
57 |
|
|
21 |
|
|
|
21 |
|
|
|
15 |
|
|
|
74 |
|
|
|
23 |
|
|
51 |
|
|
23 |
|
|
|
15 |
|
|
|
13 |
|
Transportation and processing |
|
9 |
|
|
3 |
|
|
|
2 |
|
|
|
4 |
|
|
|
7 |
|
|
|
3 |
|
|
4 |
|
|
4 |
|
|
|
- |
|
|
|
- |
|
Operating |
|
282 |
|
|
103 |
|
|
|
104 |
|
|
|
75 |
|
|
|
115 |
|
|
|
51 |
|
|
64 |
|
|
44 |
|
|
|
12 |
|
|
|
8 |
|
Operating Cash Flow |
|
829 |
|
|
298 |
|
|
|
292 |
|
|
|
239 |
|
|
|
1,122 |
|
|
|
400 |
|
|
722 |
|
|
382 |
|
|
|
182 |
|
|
|
158 |
|
Oil & NGLs - Total
Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues, Net of Royalties, excluding
Hedging |
|
1,323 |
|
|
446 |
|
|
|
505 |
|
|
|
372 |
|
|
|
2,130 |
|
|
|
561 |
|
|
1,569 |
|
|
703 |
|
|
|
442 |
|
|
|
424 |
|
Realized Financial Hedging Gain
(Loss) |
|
99 |
|
|
59 |
|
|
|
- |
|
|
|
40 |
|
|
|
78 |
|
|
|
89 |
|
|
(11) |
|
|
- |
|
|
|
(11 |
) |
|
|
- |
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and mineral taxes |
|
57 |
|
|
21 |
|
|
|
21 |
|
|
|
15 |
|
|
|
84 |
|
|
|
23 |
|
|
61 |
|
|
26 |
|
|
|
19 |
|
|
|
16 |
|
Transportation and processing |
|
47 |
|
|
14 |
|
|
|
15 |
|
|
|
18 |
|
|
|
69 |
|
|
|
19 |
|
|
50 |
|
|
20 |
|
|
|
16 |
|
|
|
14 |
|
Operating |
|
295 |
|
|
105 |
|
|
|
109 |
|
|
|
81 |
|
|
|
143 |
|
|
|
61 |
|
|
82 |
|
|
52 |
|
|
|
16 |
|
|
|
14 |
|
Operating Cash Flow |
|
1,023 |
|
|
365 |
|
|
|
360 |
|
|
|
298 |
|
|
|
1,912 |
|
|
|
547 |
|
|
1,365 |
|
|
605 |
|
|
|
380 |
|
|
|
380 |
|
|
|
|
|
|
Supplemental Information Prepared in US$ |
Third quarter report
for the
period ended September 30, 2015
Supplemental Oil and Gas Operating Statistics (unaudited)
Operating Statistics - After
Royalties
Per-unit Results, Excluding the Impact of Realized Financial Hedging
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2015 |
|
|
2014 |
|
|
|
Year-to-
date |
|
Q3 |
|
|
Q2 |
|
|
Q1 |
|
|
Year |
|
|
Q4 |
|
|
Q3 Year-
to-date |
|
Q3 |
|
|
Q2 |
|
|
Q1 |
|
Natural Gas - Canadian Operations ($/Mcf) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price (1) |
|
3.00 |
|
|
2.48 |
|
|
|
2.39 |
|
|
|
3.89 |
|
|
|
4.89 |
|
|
|
3.93 |
|
|
5.14 |
|
|
3.78 |
|
|
|
4.27 |
|
|
|
7.17 |
|
Production and mineral taxes |
|
- |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
0.01 |
|
|
|
0.01 |
|
|
0.01 |
|
|
0.01 |
|
|
|
- |
|
|
|
0.01 |
|
Transportation and processing |
|
1.76 |
|
|
1.77 |
|
|
|
1.97 |
|
|
|
1.60 |
|
|
|
1.53 |
|
|
|
1.73 |
|
|
1.48 |
|
|
1.47 |
|
|
|
1.57 |
|
|
|
1.42 |
|
Operating |
|
0.42 |
|
|
0.44 |
|
|
|
0.49 |
|
|
|
0.35 |
|
|
|
0.55 |
|
|
|
0.55 |
|
|
0.55 |
|
|
0.52 |
|
|
|
0.55 |
|
|
|
0.59 |
|
Netback |
|
0.82 |
|
|
0.27 |
|
|
|
(0.07 |
) |
|
|
1.94 |
|
|
|
2.80 |
|
|
|
1.64 |
|
|
3.10 |
|
|
1.78 |
|
|
|
2.15 |
|
|
|
5.15 |
|
Natural Gas - USA Operations
($/Mcf) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price |
|
2.69 |
|
|
2.75 |
|
|
|
2.33 |
|
|
|
2.97 |
|
|
|
4.62 |
|
|
|
3.95 |
|
|
4.78 |
|
|
4.05 |
|
|
|
4.72 |
|
|
|
5.34 |
|
Production and mineral taxes |
|
0.08 |
|
|
0.11 |
|
|
|
0.08 |
|
|
|
0.06 |
|
|
|
0.12 |
|
|
|
0.17 |
|
|
0.11 |
|
|
(0.14 |
) |
|
|
0.15 |
|
|
|
0.26 |
|
Transportation and processing |
|
2.35 |
|
|
2.47 |
|
|
|
2.27 |
|
|
|
2.30 |
|
|
|
1.83 |
|
|
|
2.16 |
|
|
1.76 |
|
|
2.13 |
|
|
|
1.80 |
|
|
|
1.46 |
|
Operating |
|
0.71 |
|
|
0.62 |
|
|
|
0.74 |
|
|
|
0.75 |
|
|
|
0.66 |
|
|
|
0.75 |
|
|
0.64 |
|
|
0.65 |
|
|
|
0.67 |
|
|
|
0.61 |
|
Netback |
|
(0.45) |
|
|
(0.45 |
) |
|
|
(0.76 |
) |
|
|
(0.14 |
) |
|
|
2.01 |
|
|
|
0.87 |
|
|
2.27 |
|
|
1.41 |
|
|
|
2.10 |
|
|
|
3.01 |
|
Natural Gas - Total Operations
($/Mcf) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price (2) |
|
2.87 |
|
|
2.60 |
|
|
|
2.37 |
|
|
|
3.53 |
|
|
|
4.78 |
|
|
|
3.94 |
|
|
4.99 |
|
|
3.88 |
|
|
|
4.46 |
|
|
|
6.37 |
|
Production and mineral taxes |
|
0.04 |
|
|
0.05 |
|
|
|
0.04 |
|
|
|
0.02 |
|
|
|
0.06 |
|
|
|
0.08 |
|
|
0.05 |
|
|
(0.05 |
) |
|
|
0.06 |
|
|
|
0.12 |
|
Transportation and processing |
|
2.01 |
|
|
2.07 |
|
|
|
2.10 |
|
|
|
1.88 |
|
|
|
1.66 |
|
|
|
1.90 |
|
|
1.60 |
|
|
1.72 |
|
|
|
1.67 |
|
|
|
1.44 |
|
Operating |
|
0.54 |
|
|
0.52 |
|
|
|
0.60 |
|
|
|
0.51 |
|
|
|
0.60 |
|
|
|
0.63 |
|
|
0.59 |
|
|
0.57 |
|
|
|
0.60 |
|
|
|
0.60 |
|
Netback |
|
0.28 |
|
|
(0.04 |
) |
|
|
(0.37 |
) |
|
|
1.12 |
|
|
|
2.46 |
|
|
|
1.33 |
|
|
2.75 |
|
|
1.64 |
|
|
|
2.13 |
|
|
|
4.21 |
|
Oil & NGLs - Canadian Operations
($/bbl) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price |
|
32.91 |
|
|
29.75 |
|
|
|
38.57 |
|
|
|
30.65 |
|
|
|
64.16 |
|
|
|
57.50 |
|
|
65.73 |
|
|
64.79 |
|
|
|
66.13 |
|
|
|
66.36 |
|
Production and mineral taxes |
|
0.01 |
|
|
(0.02 |
) |
|
|
- |
|
|
|
0.04 |
|
|
|
0.71 |
|
|
|
0.10 |
|
|
0.85 |
|
|
0.67 |
|
|
|
1.12 |
|
|
|
0.80 |
|
Transportation and processing |
|
5.07 |
|
|
3.95 |
|
|
|
5.46 |
|
|
|
5.82 |
|
|
|
4.52 |
|
|
|
5.92 |
|
|
4.19 |
|
|
4.21 |
|
|
|
4.60 |
|
|
|
3.80 |
|
Operating |
|
1.81 |
|
|
1.22 |
|
|
|
1.91 |
|
|
|
2.31 |
|
|
|
2.09 |
|
|
|
4.00 |
|
|
1.64 |
|
|
2.05 |
|
|
|
1.06 |
|
|
|
1.75 |
|
Netback |
|
26.02 |
|
|
24.60 |
|
|
|
31.20 |
|
|
|
22.48 |
|
|
|
56.84 |
|
|
|
47.48 |
|
|
59.05 |
|
|
57.86 |
|
|
|
59.35 |
|
|
|
60.01 |
|
Oil & NGLs - USA Operations
($/bbl) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price |
|
38.65 |
|
|
35.66 |
|
|
|
45.21 |
|
|
|
35.18 |
|
|
|
69.54 |
|
|
|
57.30 |
|
|
77.63 |
|
|
79.43 |
|
|
|
77.46 |
|
|
|
73.61 |
|
Production and mineral taxes |
|
2.01 |
|
|
1.95 |
|
|
|
2.26 |
|
|
|
1.80 |
|
|
|
4.10 |
|
|
|
3.16 |
|
|
4.72 |
|
|
4.18 |
|
|
|
5.19 |
|
|
|
5.46 |
|
Transportation and processing |
|
0.32 |
|
|
0.31 |
|
|
|
0.24 |
|
|
|
0.43 |
|
|
|
0.39 |
|
|
|
0.49 |
|
|
0.33 |
|
|
0.63 |
|
|
|
- |
|
|
|
- |
|
Operating |
|
10.09 |
|
|
9.95 |
|
|
|
11.28 |
|
|
|
8.96 |
|
|
|
6.36 |
|
|
|
7.11 |
|
|
5.87 |
|
|
7.80 |
|
|
|
4.29 |
|
|
|
3.16 |
|
Netback |
|
26.23 |
|
|
23.45 |
|
|
|
31.43 |
|
|
|
23.99 |
|
|
|
58.69 |
|
|
|
46.54 |
|
|
66.71 |
|
|
66.82 |
|
|
|
67.98 |
|
|
|
64.99 |
|
Oil & NGLs - Total Operations
($/bbl) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price |
|
37.45 |
|
|
34.52 |
|
|
|
43.83 |
|
|
|
34.13 |
|
|
|
67.24 |
|
|
|
57.35 |
|
|
71.66 |
|
|
73.48 |
|
|
|
71.23 |
|
|
|
69.23 |
|
Production and mineral taxes |
|
1.59 |
|
|
1.57 |
|
|
|
1.79 |
|
|
|
1.40 |
|
|
|
2.65 |
|
|
|
2.35 |
|
|
2.78 |
|
|
2.75 |
|
|
|
2.95 |
|
|
|
2.65 |
|
Transportation and processing |
|
1.32 |
|
|
1.02 |
|
|
|
1.32 |
|
|
|
1.67 |
|
|
|
2.16 |
|
|
|
1.93 |
|
|
2.27 |
|
|
2.09 |
|
|
|
2.53 |
|
|
|
2.30 |
|
Operating |
|
8.36 |
|
|
8.25 |
|
|
|
9.35 |
|
|
|
7.43 |
|
|
|
4.54 |
|
|
|
6.29 |
|
|
3.74 |
|
|
5.46 |
|
|
|
2.51 |
|
|
|
2.31 |
|
Netback |
|
26.18 |
|
|
23.68 |
|
|
|
31.37 |
|
|
|
23.63 |
|
|
|
57.89 |
|
|
|
46.78 |
|
|
62.87 |
|
|
63.18 |
|
|
|
63.24 |
|
|
|
61.97 |
|
Total - Canadian Operations
($/BOE) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price |
|
20.17 |
|
|
17.22 |
|
|
|
18.05 |
|
|
|
24.30 |
|
|
|
34.21 |
|
|
|
28.06 |
|
|
35.76 |
|
|
29.21 |
|
|
|
31.02 |
|
|
|
46.20 |
|
Production and mineral taxes |
|
0.01 |
|
|
0.01 |
|
|
|
- |
|
|
|
0.02 |
|
|
|
0.15 |
|
|
|
0.09 |
|
|
0.16 |
|
|
0.15 |
|
|
|
0.16 |
|
|
|
0.18 |
|
Transportation and processing |
|
9.79 |
|
|
9.55 |
|
|
|
10.85 |
|
|
|
9.12 |
|
|
|
8.55 |
|
|
|
9.79 |
|
|
8.24 |
|
|
8.10 |
|
|
|
8.76 |
|
|
|
7.87 |
|
Operating |
|
2.43 |
|
|
2.42 |
|
|
|
2.80 |
|
|
|
2.14 |
|
|
|
3.14 |
|
|
|
3.39 |
|
|
3.09 |
|
|
2.96 |
|
|
|
2.98 |
|
|
|
3.29 |
|
Netback |
|
7.94 |
|
|
5.24 |
|
|
|
4.40 |
|
|
|
13.02 |
|
|
|
22.37 |
|
|
|
14.79 |
|
|
24.27 |
|
|
18.00 |
|
|
|
19.12 |
|
|
|
34.86 |
|
Total - USA Operations ($/BOE) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price |
|
26.69 |
|
|
26.13 |
|
|
|
28.61 |
|
|
|
25.34 |
|
|
|
37.53 |
|
|
|
36.64 |
|
|
37.81 |
|
|
41.38 |
|
|
|
35.48 |
|
|
|
36.82 |
|
Production and mineral taxes |
|
1.20 |
|
|
1.30 |
|
|
|
1.33 |
|
|
|
0.97 |
|
|
|
1.53 |
|
|
|
1.84 |
|
|
1.44 |
|
|
0.72 |
|
|
|
1.51 |
|
|
|
1.99 |
|
Transportation and processing |
|
7.62 |
|
|
7.52 |
|
|
|
7.34 |
|
|
|
8.02 |
|
|
|
8.52 |
|
|
|
8.17 |
|
|
8.64 |
|
|
9.03 |
|
|
|
9.23 |
|
|
|
7.75 |
|
Operating |
|
6.98 |
|
|
6.85 |
|
|
|
7.66 |
|
|
|
6.44 |
|
|
|
4.53 |
|
|
|
5.51 |
|
|
4.22 |
|
|
5.12 |
|
|
|
4.05 |
|
|
|
3.60 |
|
Netback |
|
10.89 |
|
|
10.46 |
|
|
|
12.28 |
|
|
|
9.91 |
|
|
|
22.95 |
|
|
|
21.12 |
|
|
23.51 |
|
|
26.51 |
|
|
|
20.69 |
|
|
|
23.48 |
|
Total Operations Netback ($/BOE) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price |
|
23.68 |
|
|
22.26 |
|
|
|
23.90 |
|
|
|
24.82 |
|
|
|
35.67 |
|
|
|
32.25 |
|
|
36.64 |
|
|
34.36 |
|
|
|
32.93 |
|
|
|
42.12 |
|
Production and mineral taxes |
|
0.65 |
|
|
0.74 |
|
|
|
0.73 |
|
|
|
0.49 |
|
|
|
0.76 |
|
|
|
0.94 |
|
|
0.71 |
|
|
0.39 |
|
|
|
0.74 |
|
|
|
0.97 |
|
Transportation and processing |
|
8.62 |
|
|
8.41 |
|
|
|
8.91 |
|
|
|
8.57 |
|
|
|
8.54 |
|
|
|
9.00 |
|
|
8.41 |
|
|
8.50 |
|
|
|
8.96 |
|
|
|
7.82 |
|
Operating (3) |
|
4.89 |
|
|
4.93 |
|
|
|
5.50 |
|
|
|
4.27 |
|
|
|
3.76 |
|
|
|
4.43 |
|
|
3.57 |
|
|
3.87 |
|
|
|
3.44 |
|
|
|
3.43 |
|
Netback |
|
9.52 |
|
|
8.18 |
|
|
|
8.76 |
|
|
|
11.49 |
|
|
|
22.61 |
|
|
|
17.88 |
|
|
23.95 |
|
|
21.60 |
|
|
|
19.79 |
|
|
|
29.90 |
|
|
(1) |
Canadian Operations price reflects Deep Panuke price for 2015 year-to-date of $9.40/Mcf on natural gas production volumes of 71 MMcf/d. Excluding the impact
of the Deep Panuke operations, the natural gas price for 2015 year-to-date is $2.50/Mcf. |
|
(2) |
Excluding the impact of the Deep Panuke operations, the natural gas price for 2015 year-to-date is $2.58/Mcf. |
|
(3) |
2015 year-to-date operating expense includes a recovery of costs related to long-term incentives of $0.04/BOE (2014 year-to-date - costs of $0.18/BOE).
|
|
|
|
Supplemental Information
Prepared in US$ |
|
|
Third quarter report
for the period ended September 30, 2015
Supplemental Oil and
Gas Operating Statistics (unaudited)
Operating Statistics - After Royalties (continued)
Impact of Realized Financial Hedging
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2015 |
|
|
2014 |
|
|
|
Year-to-
date |
|
Q3 |
|
|
Q2 |
|
|
Q1 |
|
|
Year |
|
|
Q4 |
|
|
Q3 Year-
to-date |
|
Q3 |
|
|
Q2 |
|
|
Q1 |
|
Natural Gas ($/Mcf) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
1.39 |
|
|
1.28 |
|
|
|
1.32 |
|
|
|
1.52 |
|
|
|
(0.15 |
) |
|
|
0.24 |
|
|
(0.25) |
|
|
0.16 |
|
|
|
(0.33 |
) |
|
|
(0.53 |
) |
USA Operations |
|
0.88 |
|
|
0.88 |
|
|
|
0.93 |
|
|
|
0.82 |
|
|
|
(0.24 |
) |
|
|
0.19 |
|
|
(0.34) |
|
|
0.12 |
|
|
|
(0.44 |
) |
|
|
(0.58 |
) |
Total Operations |
|
1.17 |
|
|
1.11 |
|
|
|
1.15 |
|
|
|
1.25 |
|
|
|
(0.19 |
) |
|
|
0.22 |
|
|
(0.29) |
|
|
0.15 |
|
|
|
(0.38 |
) |
|
|
(0.55 |
) |
Oil & NGLs ($/bbl) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
0.25 |
|
|
2.09 |
|
|
|
(2.21 |
) |
|
|
0.78 |
|
|
|
1.36 |
|
|
|
9.35 |
|
|
(0.52) |
|
|
(0.31 |
) |
|
|
(1.22 |
) |
|
|
(0.09 |
) |
USA Operations |
|
3.46 |
|
|
5.17 |
|
|
|
0.52 |
|
|
|
4.58 |
|
|
|
3.29 |
|
|
|
8.94 |
|
|
(0.45) |
|
|
0.25 |
|
|
|
(2.28 |
) |
|
|
0.04 |
|
Total Operations |
|
2.79 |
|
|
4.57 |
|
|
|
(0.05 |
) |
|
|
3.70 |
|
|
|
2.46 |
|
|
|
9.05 |
|
|
(0.48) |
|
|
0.02 |
|
|
|
(1.70 |
) |
|
|
(0.04 |
) |
Total ($/BOE) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
7.15 |
|
|
6.82 |
|
|
|
6.39 |
|
|
|
8.04 |
|
|
|
(0.57 |
) |
|
|
2.49 |
|
|
(1.34) |
|
|
0.78 |
|
|
|
(1.89 |
) |
|
|
(2.77 |
) |
USA Operations |
|
4.42 |
|
|
5.21 |
|
|
|
3.22 |
|
|
|
4.78 |
|
|
|
(0.33 |
) |
|
|
4.15 |
|
|
(1.76) |
|
|
0.58 |
|
|
|
(2.57 |
) |
|
|
(3.07 |
) |
Total Operations |
|
5.68 |
|
|
5.91 |
|
|
|
4.63 |
|
|
|
6.42 |
|
|
|
(0.46 |
) |
|
|
3.30 |
|
|
(1.52) |
|
|
0.70 |
|
|
|
(2.18 |
) |
|
|
(2.90 |
) |
Per-unit Results, Including the Impact of Realized
Financial Hedging |
|
|
|
2015 |
|
|
|
2014 |
|
|
|
Year-to-
date |
|
|
Q3 |
|
|
|
Q2 |
|
|
|
Q1 |
|
|
|
Year |
|
|
|
Q4 |
|
|
Q3 Year-
to-date |
|
|
Q3 |
|
|
|
Q2 |
|
|
|
Q1 |
|
Natural Gas Price ($/Mcf) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
4.39 |
|
|
3.76 |
|
|
|
3.71 |
|
|
|
5.41 |
|
|
|
4.74 |
|
|
|
4.17 |
|
|
4.89 |
|
|
3.94 |
|
|
|
3.94 |
|
|
|
6.64 |
|
USA Operations |
|
3.57 |
|
|
3.63 |
|
|
|
3.26 |
|
|
|
3.79 |
|
|
|
4.38 |
|
|
|
4.14 |
|
|
4.44 |
|
|
4.17 |
|
|
|
4.28 |
|
|
|
4.76 |
|
Total Operations |
|
4.04 |
|
|
3.71 |
|
|
|
3.52 |
|
|
|
4.78 |
|
|
|
4.59 |
|
|
|
4.16 |
|
|
4.70 |
|
|
4.03 |
|
|
|
4.08 |
|
|
|
5.82 |
|
Natural Gas Netback ($/Mcf) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
2.21 |
|
|
1.55 |
|
|
|
1.25 |
|
|
|
3.46 |
|
|
|
2.65 |
|
|
|
1.88 |
|
|
2.85 |
|
|
1.94 |
|
|
|
1.82 |
|
|
|
4.62 |
|
USA Operations |
|
0.43 |
|
|
0.43 |
|
|
|
0.17 |
|
|
|
0.68 |
|
|
|
1.77 |
|
|
|
1.06 |
|
|
1.93 |
|
|
1.53 |
|
|
|
1.66 |
|
|
|
2.43 |
|
Total Operations |
|
1.45 |
|
|
1.07 |
|
|
|
0.78 |
|
|
|
2.37 |
|
|
|
2.27 |
|
|
|
1.55 |
|
|
2.46 |
|
|
1.79 |
|
|
|
1.75 |
|
|
|
3.66 |
|
Oil & NGLs Price
($/bbl) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
33.16 |
|
|
31.84 |
|
|
|
36.36 |
|
|
|
31.43 |
|
|
|
65.52 |
|
|
|
66.85 |
|
|
65.21 |
|
|
64.48 |
|
|
|
64.91 |
|
|
|
66.27 |
|
USA Operations |
|
42.11 |
|
|
40.83 |
|
|
|
45.73 |
|
|
|
39.76 |
|
|
|
72.83 |
|
|
|
66.24 |
|
|
77.18 |
|
|
79.68 |
|
|
|
75.18 |
|
|
|
73.65 |
|
Total Operations |
|
40.24 |
|
|
39.09 |
|
|
|
43.78 |
|
|
|
37.83 |
|
|
|
69.70 |
|
|
|
66.40 |
|
|
71.18 |
|
|
73.50 |
|
|
|
69.53 |
|
|
|
69.19 |
|
Oil & NGLs Netback
($/bbl) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
26.27 |
|
|
26.69 |
|
|
|
28.99 |
|
|
|
23.26 |
|
|
|
58.20 |
|
|
|
56.83 |
|
|
58.53 |
|
|
57.55 |
|
|
|
58.13 |
|
|
|
59.92 |
|
USA Operations |
|
29.69 |
|
|
28.62 |
|
|
|
31.95 |
|
|
|
28.57 |
|
|
|
61.98 |
|
|
|
55.48 |
|
|
66.26 |
|
|
67.07 |
|
|
|
65.70 |
|
|
|
65.03 |
|
Total Operations |
|
28.97 |
|
|
28.25 |
|
|
|
31.32 |
|
|
|
27.33 |
|
|
|
60.35 |
|
|
|
55.83 |
|
|
62.39 |
|
|
63.20 |
|
|
|
61.54 |
|
|
|
61.93 |
|
Total Price ($/BOE) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
27.32 |
|
|
24.04 |
|
|
|
24.44 |
|
|
|
32.34 |
|
|
|
33.64 |
|
|
|
30.55 |
|
|
34.42 |
|
|
29.99 |
|
|
|
29.13 |
|
|
|
43.43 |
|
USA Operations |
|
31.11 |
|
|
31.34 |
|
|
|
31.83 |
|
|
|
30.12 |
|
|
|
37.20 |
|
|
|
40.79 |
|
|
36.05 |
|
|
41.96 |
|
|
|
32.91 |
|
|
|
33.75 |
|
Total Operations |
|
29.36 |
|
|
28.17 |
|
|
|
28.53 |
|
|
|
31.24 |
|
|
|
35.21 |
|
|
|
35.55 |
|
|
35.12 |
|
|
35.06 |
|
|
|
30.75 |
|
|
|
39.22 |
|
Total Netback ($/BOE) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
15.09 |
|
|
12.06 |
|
|
|
10.79 |
|
|
|
21.06 |
|
|
|
21.80 |
|
|
|
17.28 |
|
|
22.93 |
|
|
18.78 |
|
|
|
17.23 |
|
|
|
32.09 |
|
USA Operations |
|
15.31 |
|
|
15.67 |
|
|
|
15.50 |
|
|
|
14.69 |
|
|
|
22.62 |
|
|
|
25.27 |
|
|
21.75 |
|
|
27.09 |
|
|
|
18.12 |
|
|
|
20.41 |
|
Total Operations |
|
15.20 |
|
|
14.09 |
|
|
|
13.39 |
|
|
|
17.91 |
|
|
|
22.15 |
|
|
|
21.18 |
|
|
22.43 |
|
|
22.30 |
|
|
|
17.61 |
|
|
|
27.00 |
|
|
|
|
|
|
Supplemental Information Prepared in US$ |
Third quarter report
for the period ended September 30, 2015
Supplemental Oil
and Gas Operating Statistics (unaudited)
Results by Play
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2015 |
|
|
|
|
2014 |
|
(after royalties) |
|
Year-to-
date |
|
Q3 |
|
|
Q2 |
|
|
Q1 |
|
|
|
|
Year |
|
|
Q4 |
|
|
Q3 Year-
to-date |
|
Q3 |
|
|
Q2 |
|
|
Q1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Production (MMcf/d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Montney (1) |
|
705 |
|
|
711 |
|
|
|
685 |
|
|
|
717 |
|
|
|
|
|
639 |
|
|
|
687 |
|
|
623 |
|
|
644 |
|
|
|
604 |
|
|
|
620 |
|
Duvernay |
|
20 |
|
|
26 |
|
|
|
17 |
|
|
|
16 |
|
|
|
|
|
11 |
|
|
|
12 |
|
|
11 |
|
|
15 |
|
|
|
9 |
|
|
|
8 |
|
Other Upstream Operations (2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wheatland (3) |
|
89 |
|
|
80 |
|
|
|
76 |
|
|
|
111 |
|
|
|
|
|
292 |
|
|
|
249 |
|
|
307 |
|
|
291 |
|
|
|
305 |
|
|
|
324 |
|
Bighorn |
|
1 |
|
|
- |
|
|
|
- |
|
|
|
4 |
|
|
|
|
|
158 |
|
|
|
(3 |
) |
|
212 |
|
|
162 |
|
|
|
230 |
|
|
|
246 |
|
Deep Panuke |
|
71 |
|
|
- |
|
|
|
32 |
|
|
|
182 |
|
|
|
|
|
190 |
|
|
|
79 |
|
|
227 |
|
|
186 |
|
|
|
243 |
|
|
|
253 |
|
Other and emerging (1) |
|
75 |
|
|
59 |
|
|
|
71 |
|
|
|
98 |
|
|
|
|
|
88 |
|
|
|
87 |
|
|
88 |
|
|
76 |
|
|
|
72 |
|
|
|
117 |
|
Total Canadian Operations |
|
961 |
|
|
876 |
|
|
|
881 |
|
|
|
1,128 |
|
|
|
|
|
1,378 |
|
|
|
1,111 |
|
|
1,468 |
|
|
1,374 |
|
|
|
1,463 |
|
|
|
1,568 |
|
USA Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Eagle Ford |
|
40 |
|
|
48 |
|
|
|
36 |
|
|
|
36 |
|
|
|
|
|
19 |
|
|
|
35 |
|
|
13 |
|
|
35 |
|
|
|
5 |
|
|
|
- |
|
Permian |
|
42 |
|
|
54 |
|
|
|
38 |
|
|
|
34 |
|
|
|
|
|
5 |
|
|
|
20 |
|
|
- |
|
|
- |
|
|
|
- |
|
|
|
- |
|
DJ Basin |
|
53 |
|
|
55 |
|
|
|
55 |
|
|
|
49 |
|
|
|
|
|
43 |
|
|
|
49 |
|
|
40 |
|
|
38 |
|
|
|
43 |
|
|
|
40 |
|
San Juan |
|
14 |
|
|
15 |
|
|
|
15 |
|
|
|
13 |
|
|
|
|
|
8 |
|
|
|
8 |
|
|
8 |
|
|
9 |
|
|
|
7 |
|
|
|
7 |
|
Other Upstream Operations (2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Piceance |
|
326 |
|
|
311 |
|
|
|
324 |
|
|
|
343 |
|
|
|
|
|
402 |
|
|
|
367 |
|
|
414 |
|
|
398 |
|
|
|
407 |
|
|
|
436 |
|
Haynesville |
|
203 |
|
|
177 |
|
|
|
204 |
|
|
|
230 |
|
|
|
|
|
311 |
|
|
|
252 |
|
|
331 |
|
|
298 |
|
|
|
365 |
|
|
|
331 |
|
Jonah |
|
- |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
|
|
100 |
|
|
|
- |
|
|
134 |
|
|
- |
|
|
|
124 |
|
|
|
282 |
|
East Texas |
|
- |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
|
|
57 |
|
|
|
- |
|
|
77 |
|
|
21 |
|
|
|
97 |
|
|
|
113 |
|
Other and emerging |
|
17 |
|
|
11 |
|
|
|
15 |
|
|
|
24 |
|
|
|
|
|
27 |
|
|
|
19 |
|
|
30 |
|
|
26 |
|
|
|
30 |
|
|
|
32 |
|
Total USA Operations |
|
695 |
|
|
671 |
|
|
|
687 |
|
|
|
729 |
|
|
|
|
|
972 |
|
|
|
750 |
|
|
1,047 |
|
|
825 |
|
|
|
1,078 |
|
|
|
1,241 |
|
Oil & NGLs Production
(Mbbls/d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Montney (1) |
|
22.3 |
|
|
21.8 |
|
|
|
21.6 |
|
|
|
23.3 |
|
|
|
|
|
18.9 |
|
|
|
24.8 |
|
|
16.9 |
|
|
20.8 |
|
|
|
13.3 |
|
|
|
16.2 |
|
Duvernay |
|
3.6 |
|
|
4.9 |
|
|
|
3.0 |
|
|
|
2.8 |
|
|
|
|
|
2.1 |
|
|
|
2.5 |
|
|
1.9 |
|
|
2.6 |
|
|
|
1.8 |
|
|
|
1.4 |
|
Other Upstream Operations (2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wheatland (3) |
|
1.1 |
|
|
0.4 |
|
|
|
1.2 |
|
|
|
1.7 |
|
|
|
|
|
8.6 |
|
|
|
2.0 |
|
|
10.9 |
|
|
9.9 |
|
|
|
11.3 |
|
|
|
11.3 |
|
Bighorn |
|
- |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
|
|
7.5 |
|
|
|
(1.5 |
) |
|
10.6 |
|
|
8.7 |
|
|
|
11.0 |
|
|
|
12.1 |
|
Other and emerging (1) |
|
0.1 |
|
|
0.1 |
|
|
|
0.5 |
|
|
|
- |
|
|
|
|
|
0.1 |
|
|
|
0.4 |
|
|
- |
|
|
0.3 |
|
|
|
- |
|
|
|
- |
|
Total Canadian Operations |
|
27.1 |
|
|
27.2 |
|
|
|
26.3 |
|
|
|
27.8 |
|
|
|
|
|
37.2 |
|
|
|
28.2 |
|
|
40.3 |
|
|
42.3 |
|
|
|
37.4 |
|
|
|
41.0 |
|
USA Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Eagle Ford |
|
40.6 |
|
|
46.0 |
|
|
|
39.8 |
|
|
|
36.0 |
|
|
|
|
|
19.8 |
|
|
|
36.1 |
|
|
14.3 |
|
|
37.6 |
|
|
|
5.0 |
|
|
|
- |
|
Permian |
|
31.0 |
|
|
36.7 |
|
|
|
29.5 |
|
|
|
26.7 |
|
|
|
|
|
3.5 |
|
|
|
13.8 |
|
|
- |
|
|
- |
|
|
|
- |
|
|
|
- |
|
DJ Basin |
|
15.2 |
|
|
16.1 |
|
|
|
15.3 |
|
|
|
14.3 |
|
|
|
|
|
11.6 |
|
|
|
14.0 |
|
|
10.8 |
|
|
11.8 |
|
|
|
10.1 |
|
|
|
10.5 |
|
San Juan |
|
6.7 |
|
|
6.8 |
|
|
|
6.4 |
|
|
|
6.7 |
|
|
|
|
|
3.9 |
|
|
|
5.6 |
|
|
3.4 |
|
|
3.5 |
|
|
|
3.9 |
|
|
|
2.7 |
|
Other Upstream Operations (2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Piceance |
|
3.6 |
|
|
3.5 |
|
|
|
3.7 |
|
|
|
3.7 |
|
|
|
|
|
5.0 |
|
|
|
4.3 |
|
|
5.2 |
|
|
4.8 |
|
|
|
5.3 |
|
|
|
5.4 |
|
Jonah |
|
- |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
|
|
1.8 |
|
|
|
- |
|
|
2.4 |
|
|
0.2 |
|
|
|
2.5 |
|
|
|
4.7 |
|
East Texas |
|
- |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
|
|
0.5 |
|
|
|
- |
|
|
0.7 |
|
|
- |
|
|
|
1.0 |
|
|
|
1.2 |
|
Other and emerging |
|
5.3 |
|
|
4.1 |
|
|
|
6.3 |
|
|
|
5.5 |
|
|
|
|
|
3.5 |
|
|
|
4.4 |
|
|
3.1 |
|
|
3.8 |
|
|
|
3.0 |
|
|
|
2.4 |
|
Total USA Operations |
|
102.4 |
|
|
113.2 |
|
|
|
101.0 |
|
|
|
92.9 |
|
|
|
|
|
49.6 |
|
|
|
78.2 |
|
|
39.9 |
|
|
61.7 |
|
|
|
30.8 |
|
|
|
26.9 |
|
|
(1) |
Montney has been realigned to include certain production volumes which were previously reported in Other and emerging. |
|
(2) |
Other Upstream Operations includes results from plays that are not part of the Companys current strategic focus as well as prospective plays which are
under appraisal, including the TMS which is reported in Other and emerging in the USA Operations. |
|
(3) |
Wheatland was previously presented as Clearwater. |
|
|
|
Supplemental Information
Prepared in US$ |
|
|
Third quarter report
for the period ended September 30, 2015
Supplemental Oil and
Gas Operating Statistics (unaudited)
Results by Play (continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2015 |
|
|
2014 |
|
|
|
Year-to-
date |
|
Q3 |
|
|
Q2 |
|
|
Q1 |
|
|
Year |
|
|
Q4 |
|
|
Q3 Year-
to-date |
|
Q3 |
|
|
Q2 |
|
|
Q1 |
|
|
|
|
|
|
|
|
|
|
|
|
Drilling Activity (net wells drilled) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Montney |
|
14 |
|
|
- |
|
|
|
6 |
|
|
|
8 |
|
|
|
79 |
|
|
|
14 |
|
|
65 |
|
|
15 |
|
|
|
23 |
|
|
|
27 |
|
Duvernay |
|
9 |
|
|
2 |
|
|
|
1 |
|
|
|
6 |
|
|
|
24 |
|
|
|
5 |
|
|
19 |
|
|
7 |
|
|
|
6 |
|
|
|
6 |
|
Other Upstream Operations (1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wheatland (2) |
|
105 |
|
|
34 |
|
|
|
- |
|
|
|
71 |
|
|
|
174 |
|
|
|
84 |
|
|
90 |
|
|
24 |
|
|
|
- |
|
|
|
66 |
|
Bighorn |
|
- |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
1 |
|
|
|
- |
|
|
1 |
|
|
1 |
|
|
|
- |
|
|
|
- |
|
Other and emerging |
|
- |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
1 |
|
|
|
- |
|
|
1 |
|
|
1 |
|
|
|
- |
|
|
|
- |
|
Total Canadian Operations |
|
128 |
|
|
36 |
|
|
|
7 |
|
|
|
85 |
|
|
|
279 |
|
|
|
103 |
|
|
176 |
|
|
48 |
|
|
|
29 |
|
|
|
99 |
|
USA Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Eagle Ford |
|
51 |
|
|
10 |
|
|
|
14 |
|
|
|
27 |
|
|
|
35 |
|
|
|
21 |
|
|
14 |
|
|
14 |
|
|
|
- |
|
|
|
- |
|
Permian |
|
142 |
|
|
44 |
|
|
|
52 |
|
|
|
46 |
|
|
|
28 |
|
|
|
28 |
|
|
- |
|
|
- |
|
|
|
- |
|
|
|
- |
|
DJ Basin |
|
15 |
|
|
- |
|
|
|
2 |
|
|
|
13 |
|
|
|
64 |
|
|
|
15 |
|
|
49 |
|
|
17 |
|
|
|
14 |
|
|
|
18 |
|
San Juan |
|
1 |
|
|
- |
|
|
|
- |
|
|
|
1 |
|
|
|
43 |
|
|
|
19 |
|
|
24 |
|
|
15 |
|
|
|
5 |
|
|
|
4 |
|
Other Upstream Operations (1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Piceance |
|
- |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
1 |
|
|
|
- |
|
|
1 |
|
|
- |
|
|
|
- |
|
|
|
1 |
|
Haynesville |
|
2 |
|
|
2 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
- |
|
|
- |
|
|
|
- |
|
|
|
- |
|
Jonah |
|
- |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
18 |
|
|
|
- |
|
|
18 |
|
|
- |
|
|
|
6 |
|
|
|
12 |
|
East Texas |
|
- |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
- |
|
|
- |
|
|
|
- |
|
|
|
- |
|
Other and emerging |
|
3 |
|
|
- |
|
|
|
- |
|
|
|
3 |
|
|
|
15 |
|
|
|
5 |
|
|
10 |
|
|
4 |
|
|
|
4 |
|
|
|
2 |
|
Total USA Operations |
|
214 |
|
|
56 |
|
|
|
68 |
|
|
|
90 |
|
|
|
204 |
|
|
|
88 |
|
|
116 |
|
|
50 |
|
|
|
29 |
|
|
|
37 |
|
|
(1) |
Other Upstream Operations includes net wells drilled in plays that are not part of the Companys current strategic focus as well as prospective plays
which are under appraisal, including the TMS which is reported in Other and emerging in the USA Operations. |
|
(2) |
Wheatland was previously presented as Clearwater.
|
|
|
|
|
|
Supplemental Information Prepared in US$ |
Encana Corporation
Further information on Encana Corporation is
available on the
companys website, www.encana.com, or by contacting:
INVESTOR CONTACT:
Brendan McCracken
Vice-President, Investor Relations (403) 645-2978
Brendan.McCracken@encana.com
Brian Dutton (403) 645-2285
Brian.Dutton@encana.com
Patti Posadowski (403) 645-2252
Patti.Posadowski@encana.com
GENERAL INQUIRIES
Encana Corporation 500 Centre Street SE PO Box 2850
Calgary, AB , Canada T2P 2S5
Phone: 403.645.2000
Fax: 403.645.3400
encana
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