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 August 6, 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: August 6, 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 June 30, 2015, including the Unaudited Interim Condensed Consolidated Financial Statements and Managements Discussion and Analysis for the said period. |
2015 Q2 Report
For the period ended June 30, 2015
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Q2 Report | For the period ended June 30, 2015
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Encana delivers better wells, lower costs and increased well inventory
Strong operational performance in second quarter positions Encana for accelerated growth
Calgary, Alberta (July 24, 2015) TSX, NYSE: ECA
Strong second quarter operational performance helped Encana deliver its seventh consecutive quarterly increase in liquids volumes since launching its strategy to grow
high-margin production. A focused and front-end loaded capital program has positioned the company to accelerate liquids production growth in the second half of 2015. Highlights include:
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liquids production of approximately 127,300 barrels per day (bbls/d), up 87 percent year-over-year |
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over 80 percent of capital invested in the companys four most strategic assets, the Permian, Eagle Ford, Duvernay and Montney |
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59 new wells brought on production in the Eagle Ford and Permian late in the second quarter, with another 76 planned in the third quarter |
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reduced Eagle Ford drilling and completion costs by $1 million per well, or 18 percent, compared to the first quarter |
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pace-setting Duvernay wells with production rates of up to 2,000 bbls/d of condensate and 11.5 million cubic feet per day (MMcf/d) of rich gas after 27 days on production |
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significant expansion of liquids inventory in the Montney, with higher condensate yields in Dawson South and two recent Pipestone area wells each producing over 1,000 bbls/d |
Following our successful portfolio transformation in 2014, we continue to lower costs, improve well performance and increase well inventory in our four most
strategic assets, said Doug Suttles, Encana President & CEO. We exited the second quarter with significant operational momentum and we expect to accelerate liquids growth through the second half of the year.
Second quarter liquids production increased more than five percent over the previous quarter, largely attributable to continued organic growth in the companys
Eagle Ford and Permian positions. Second quarter natural gas production of approximately 1.6 billion cubic feet per day (Bcf/d) reflects a 16 percent decrease compared to the previous quarter, mainly due to divestitures, the companys seasonal
production strategy for its Deep Panuke platform and takeaway restrictions in the Montney.
Total company production averaged 389,000 (BOE/d) with Encanas four strategic assets contributing approximately
223,000 BOE/d or 57 percent. The company expects its Permian, Eagle Ford, Duvernay and Montney assets will contribute an average of approximately 270,000 BOE/d or 65 percent of total production during the fourth quarter of 2015.
Through our culture of innovation, we continue to identify and seize opportunities to enhance our performance and make our four most strategic assets bigger,
better and more efficient, said Suttles. Our core assets are located in the heart of four of the highest netback basins in North America and are delivering strong returns through the current commodity price cycle.
Consistent with its strategy to grow high-margin production, the company expects to focus its remaining 2015 capital budget on its four most strategic assets. Based on
assumptions of $50 per barrel (bbl) WTI oil prices and NYMEX natural gas prices of $3 per million British thermal units (MMBtu), Encana expects to realize average operating margins of over $25 per BOE in the Permian, Eagle Ford and Duvernay, and
$1.15 per thousand cubic feet equivalent (Mcfe) in the Montney.
Encana remains on track to deliver its 2015 cash flow guidance of between $1.4 billion and $1.6
billion. The company generated second quarter cash flow of $181 million or $0.22 per share; an operating loss of $167 million or $0.20 per share; and a net loss of $1.6 billion or $1.91 per share primarily due to a $1.3 billion non-cash, after-tax
ceiling test impairment. Year-to-date, Encana has generated $676 million in cash flow or $0.85 per share; an operating loss of $148 million or $0.19 per share; and net loss of approximately $3.3 billion or $4.15 per share, largely attributable to
non-cash, after-tax ceiling test impairments of $2.6 billion.
Encana is on track to fully fund its 2015 capital program and dividend with anticipated cash flow and
the proceeds from previously announced and completed divestitures. In addition, the company continued streamlining its organization during the second quarter to align its structure with its transformed portfolio and disciplined capital program.
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Encana Corporation |
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Q2 Report | For the period ended June 30,
2015 |
Operational highlights: Lowering costs, improving well performance and increasing well inventory
PERMIAN: BUILDING A LONG-TERM GROWTH ENGINE
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strong well performance with recent wells delivering early production rates of over 1,000 bbls/d of oil |
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innovative casing designs for vertical and horizontal drilling programs are saving on average $350,000 per well |
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average horizontal well cycle times reduced to 22 days from 26 days in the first quarter, with the best well at 15 days |
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oil gathering agreement is expected to improve operating margins by up to $2 per barrel (bbl) |
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drilled 23 net horizontal and 29 net vertical wells in the second quarter |
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second quarter production of 35,800 BOE/d, comprising 29,500 bbls/d of liquids and 38 MMcf/d of natural gas |
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significant growth expected in second half of the year as the company plans 16 horizontal wells to be brought on production in July and a further 70 wells through the remainder of 2015 |
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on track for average fourth quarter production of 50,000 BOE/d |
EAGLE FORD: GROWING INVENTORY AFTER SUCCESSFUL FIRST
YEAR
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potential to grow well inventory to over 600 drilling locations up from the initial 400 since entering the play one year ago |
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strong well results from the Graben area with a recent well on production at 1,300 bbls/d of oil and 675 thousand cubic feet per day (Mcf/d) of natural gas |
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upgrades completed at Patton Trust South facility, increasing its capacity from 5,000 bbls/d to over 18,000 bbls/d |
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drilling and completion costs lowered by $1 million per well, or 18 percent, compared to the first quarter of the year |
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achieved spud-to-rig release cycle time of less than 10 days during the second quarter |
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base decline reduced 50 percent year-to-date |
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drilled 14 net wells in the second quarter |
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second quarter production of 45,800 BOE/d, comprising 39,800 bbls/d of liquids and 36 MMcf/d of natural gas |
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significant growth expected in second half of the year as the company plans 17 wells to be brought on production in July and a further 21 wells through the remainder of 2015 |
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on track for average fourth quarter production of 57,000 BOE/d
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DUVERNAY: IMPROVING WELL PERFORMANCE, DRIVING DOWN COSTS
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pace-setting wells with production rates up to 2,000 bbls/d of condensate and 11.5 MMcf/d of rich gas after 27 days on production |
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industry-leading drilling and completions costs of approximately $10.4 million per well achieved on latest multi-well pad |
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continued efficiency gains from dual-frac spread operations, averaging nine fracs per day |
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savings of over $1 million per well in water handling costs due to the start-up of water infrastructure |
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drilled one net well in the second quarter |
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second quarter production of 5,800 BOE/d, comprising 3,000 bbls/d of liquids and 17 MMcf/d of natural gas |
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expect to bring two wells on production in July and a further 11 wells through the remainder of 2015 |
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on track for average fourth quarter production of 17,000 BOE/d |
MONTNEY: UNLOCKING SIGNIFICANT CONDENSATE POTENTIAL
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well results in the South Dawson area of Cutbank Ridge confirmed the companys predicted higher condensate yields, increasing from five barrels per million cubic feet (bbls/MMcf) of natural gas to over 40 bbls/MMcf
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initial testing of the oil window in the Pipestone area showed strong potential with two recent wells each producing 1,000 bbls/d |
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enhanced completion design delivering an average 33 percent production improvement |
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liquids production increased by 1,000 bbls/d through optimization work at the 16-34 Pipestone plant |
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realized $18 million in total cost savings at an average of $400,000 per well since the commissioning of the water resource hub near Dawson Creek, British Columbia in September 2014. The facility blends produced water
with saline water and provides nearly 90 percent of the water needed for the companys operations in the area |
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drilled six net wells in the second quarter |
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second quarter production of 135,900 BOE/d, comprising 21,600 bbls/d of liquids and 685 MMcf/d of natural gas |
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on track for average fourth quarter production of 146,000 BOE/d |
Additional information on Encanas four most
strategic assets will be available in the companys updated corporate presentation later today. Encanas updated 2015 guidance can be downloaded from the companys website at
http://www.encana.com/investors/financial/corporate-guidance.html.
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Encana Corporation |
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Q2 Report | For the period ended June 30, 2015
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ENCANAS RISK MANAGEMENT PROGRAM ADDITIONAL OIL HEDGES SECURED DURING THE SECOND QUARTER
At June 30, 2015, Encana has hedged approximately 1,000 MMcf/d of expected July to December 2015 natural gas production using NYMEX fixed price contracts at an
average price of $4.29 per Mcf. In addition, Encana has hedged approximately 59.4 thousand barrels per day (Mbbls/d) of expected July to December 2015 oil production using WTI
fixed price contracts at an average price of $61.96 per bbl and approximately 38 Mbbls/d of expected 2016 oil production at an average price of $62.83 per bbl.
DIVIDEND DECLARED
On July 23, 2015, Encanas Board of Directors
declared a dividend of $0.07 per share payable on September 30, 2015, to common shareholders of record as of September 15, 2015.
SECOND QUARTER HIGHLIGHTS
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Financial Summary |
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(for the period
ended June 30) ($ millions, except per share amounts) |
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Q2 2015 |
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Q2 2014 |
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Cash flow1 |
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181 |
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656 |
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Per share diluted |
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0.22 |
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0.89 |
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Operating earnings (loss)
1 |
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(167) |
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171 |
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Per share diluted |
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(0.20) |
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0.23 |
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Earnings
Reconciliation Summary |
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Net earnings (loss) attributable to common shareholders |
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(1,610) |
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271 |
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After-tax (addition) deduction: |
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Unrealized hedging gain (loss) |
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(187) |
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8 |
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Impairments |
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(1,328) |
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Restructuring charges |
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(10) |
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(5) |
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Non-operating foreign exchange gain (loss) |
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114 |
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156 |
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Gain (loss) on divestitures |
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1 |
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135 |
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Income tax adjustments |
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(33) |
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(194) |
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Operating earnings
(loss)1 |
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(167) |
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171 |
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Per share diluted |
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(0.20) |
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0.23 |
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1 Cash flow and operating earnings (loss) are non-GAAP measures as
defined in Note 1 on page 5.
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Production Summary |
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(for the period ended June 30)
(After royalties) |
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Q2 2015 |
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Q2 2014 |
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% D |
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Natural gas (MMcf/d) |
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1,568 |
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2,541 |
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(38) |
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Liquids (Mbbls/d) |
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127.3 |
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68.2 |
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87 |
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Natural Gas and Liquids Prices |
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Q2 2015 |
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Q2 2014 |
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Natural Gas |
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NYMEX ($/MMBtu) |
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2.64 |
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4.67 |
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Encana realized gas price1 ($/Mcf) |
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3.52 |
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4.08 |
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Oil and Natural Gas Liquids ($/bbl) |
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WTI |
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57.94 |
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102.99 |
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Encana realized liquids
price1 |
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43.78 |
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69.53 |
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1 Realized prices include the impact of financial hedging.
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Encana Corporation |
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Q2 Report | For the period ended June 30,
2015 |
A conference call and webcast to discuss the second 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 approximately 10 minutes prior to the conference call. An archived recording of the call will be available from
approximately 10 p.m. MT on July 24 until 9:59 p.m. MT on July 31, 2015 by dialing (800) 585-8367 or (416) 621-4642 and entering passcode 56243229. A live audio webcast of the conference call, including slides and additional
asset information will also be available on Encanas website, www.encana.com, under Invest In Us/Presentations & Events. The webcasts will be archived for approximately 90 days.
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. |
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.
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. 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.
ADVISORY REGARDING OIL AND GAS INFORMATION
Encana uses the term resource play. 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. In this news release, certain
natural gas volumes have been converted to barrels of oil equivalent (BOE) on the basis of six thousand cubic feet (Mcf) to one barrel (bbl). BOE may be misleading, particularly if used in isolation. A conversion ratio of six Mcf to one bbl is based
on an energy equivalency conversion method primarily applicable at the burner tip and does not represent value equivalency at the well head. Given that the value ratio based on the current price of natural gas as compared to oil is significantly
different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.
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) within the meaning of applicable
securities legislation. Forward-looking statements include, but are not limited to:
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expectation to accelerate liquids production growth in the second half of 2015 |
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number of wells for 2015 and expected production |
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the potential to grow well inventory |
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capital spending plans to grow higher margin production |
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expectation of meeting the targets in the Companys 2015 corporate guidance |
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the Companys expectation to fully fund its 2015 capital program and dividend with anticipated cash flow and proceeds from divestitures |
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improved operating margins |
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design and optimization work to improve well performance and production rates and reduce costs |
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:
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achieving average production for 2015 of between 1.60 Bcf/d and 1.70 Bcf/d of natural gas and 130,000 bbls/d to 150,000 bbls/d of liquids |
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commodity prices for natural gas and liquids based on NYMEX of $3.00 per MMBtu and WTI of $50 per bbl through the remainder of 2015 |
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U.S./Canadian dollar exchange rate of 0.80 |
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effectiveness of the Companys resource play hub model to drive productivity and efficiencies |
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results from innovations |
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Encana Corporation |
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Q2 Report | For the period ended June 30, 2015
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availability of attractive hedge contracts |
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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 |
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; 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 most recent 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 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.
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Encana Corporation |
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Q2 Report | For the period ended June 30,
2015 |
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 June 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 July 23, 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); 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).
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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Q2 Report | For the period ended June 30, 2015
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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 June 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:
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Canadian Operations includes the exploration for, development of, and production of natural gas, oil and NGLs and other related activities within
Canada. |
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USA Operations includes the exploration for, development of, and production of natural gas, oil and NGLs and other related activities within the U.S.
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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.
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MD&A
Prepared using U.S. GAAP in US$ |
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Q2 Report | For the period ended June 30,
2015 |
Highlights
In the three months ended June 30, 2015, Encana reported:
|
|
|
Cash Flow of $181 million and an Operating Loss of $167 million. |
|
|
|
Net Loss of $1,610 million, including an after-tax non-cash ceiling test impairment of $1,328 million. |
|
|
|
Average realized natural gas prices, including financial hedges, of $3.52 per Mcf. Average realized oil prices, including financial hedges, of $53.08 per
bbl. Average realized NGL prices of $24.28 per bbl. |
|
|
|
Average natural gas production volumes of 1,568 MMcf/d and average oil and NGL production volumes of 127.3 Mbbls/d. |
|
|
|
Dividends paid of $0.07 per share. |
In
the six months ended June 30, 2015, Encana reported:
|
|
|
Cash Flow of $676 million and an Operating Loss of $148 million. |
|
|
|
Net Loss of $3,317 million, including an after-tax non-cash ceiling test impairment of $2,550 million. |
|
|
|
Average realized natural gas prices, including financial hedges, of $4.20 per Mcf. Average realized oil prices, including financial hedges, of $49.80 per
bbl. Average realized NGL prices of $23.10 per bbl. |
|
|
|
Average natural gas production volumes of 1,712 MMcf/d and average oil and NGL production volumes of 124.0 Mbbls/d. |
|
|
|
Dividends paid of $0.14 per share. |
|
|
|
Cash and cash equivalents of $496 million at period end. |
Significant developments for the Company during the six months ended June 30, 2015 included the following:
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|
|
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. |
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|
|
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, on April 6, 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. |
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|
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$454 million, after closing adjustments. |
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MD&A
Prepared using U.S. GAAP in US$ |
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|
Q2 Report | For the period ended June 30, 2015
|
Financial Results
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Six months
ended June 30 |
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2015 |
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2014 |
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2013 |
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($ millions, except as indicated) |
|
2015 |
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2014 |
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Q2 |
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Q1 |
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Q4 |
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Q3 |
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Q2 |
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|
Q1 |
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Q4 |
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Q3 |
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|
Cash Flow (1) |
|
$ |
676 |
|
|
$ |
1,750 |
|
|
|
|
$ |
181 |
|
|
$ |
495 |
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|
|
|
$ |
377 |
|
|
$ |
807 |
|
|
$ |
656 |
|
|
$ |
1,094 |
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|
|
|
$ |
677 |
|
|
$ |
660 |
|
$ per share - diluted |
|
|
0.85 |
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|
2.36 |
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|
|
|
|
0.22 |
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|
0.65 |
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|
|
|
|
0.51 |
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|
1.09 |
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|
|
0.89 |
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|
1.48 |
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|
0.91 |
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|
0.89 |
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|
Operating Earnings (Loss) (1), (2) |
|
|
(148 |
) |
|
|
686 |
|
|
|
|
|
(167 |
) |
|
|
19 |
|
|
|
|
|
35 |
|
|
|
281 |
|
|
|
171 |
|
|
|
515 |
|
|
|
|
|
226 |
|
|
|
150 |
|
$ per share - diluted |
|
|
(0.19 |
) |
|
|
0.93 |
|
|
|
|
|
(0.20 |
) |
|
|
0.03 |
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|
|
|
|
0.05 |
|
|
|
0.38 |
|
|
|
0.23 |
|
|
|
0.70 |
|
|
|
|
|
0.31 |
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|
|
0.20 |
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Earnings (Loss) Attributable to Common Shareholders |
|
|
(3,317 |
) |
|
|
387 |
|
|
|
|
|
(1,610 |
) |
|
|
(1,707 |
) |
|
|
|
|
198 |
|
|
|
2,807 |
|
|
|
271 |
|
|
|
116 |
|
|
|
|
|
(251 |
) |
|
|
188 |
|
$ per share - basic & diluted |
|
|
(4.15 |
) |
|
|
0.52 |
|
|
|
|
|
(1.91 |
) |
|
|
(2.25 |
) |
|
|
|
|
0.27 |
|
|
|
3.79 |
|
|
|
0.37 |
|
|
|
0.16 |
|
|
|
|
|
(0.34 |
) |
|
|
0.25 |
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|
Revenues, Net of Royalties |
|
|
2,079 |
|
|
|
3,480 |
|
|
|
|
|
830 |
|
|
|
1,249 |
|
|
|
|
|
2,254 |
|
|
|
2,285 |
|
|
|
1,588 |
|
|
|
1,892 |
|
|
|
|
|
1,423 |
|
|
|
1,392 |
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized Hedging Gain (Loss), before tax |
|
|
401 |
|
|
|
(243 |
) |
|
|
|
|
161 |
|
|
|
240 |
|
|
|
|
|
124 |
|
|
|
28 |
|
|
|
(102 |
) |
|
|
(141 |
) |
|
|
|
|
174 |
|
|
|
175 |
|
Unrealized Hedging Gain (Loss), before tax |
|
|
(414 |
) |
|
|
(276 |
) |
|
|
|
|
(278 |
) |
|
|
(136 |
) |
|
|
|
|
489 |
|
|
|
231 |
|
|
|
9 |
|
|
|
(285 |
) |
|
|
|
|
(301 |
) |
|
|
(128 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Upstream Operating Cash Flow |
|
|
1,181 |
|
|
|
2,115 |
|
|
|
|
|
479 |
|
|
|
702 |
|
|
|
|
|
821 |
|
|
|
982 |
|
|
|
800 |
|
|
|
1,315 |
|
|
|
|
|
901 |
|
|
|
794 |
|
Upstream Operating Cash Flow Excluding Realized Hedging (1) |
|
|
769 |
|
|
|
2,353 |
|
|
|
|
|
315 |
|
|
|
454 |
|
|
|
|
|
694 |
|
|
|
952 |
|
|
|
898 |
|
|
|
1,455 |
|
|
|
|
|
728 |
|
|
|
622 |
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|
Capital Investment |
|
|
1,479 |
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|
|
1,071 |
|
|
|
|
|
743 |
|
|
|
736 |
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|
857 |
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|
598 |
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|
560 |
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|
511 |
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|
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|
717 |
|
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|
641 |
|
Net Acquisitions & (Divestitures) (3) |
|
|
(978 |
) |
|
|
628 |
|
|
|
|
|
(140 |
) |
|
|
(838 |
) |
|
|
|
|
50 |
|
|
|
(2,007 |
) |
|
|
652 |
|
|
|
(24 |
) |
|
|
|
|
(72 |
) |
|
|
(51 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Free Cash Flow (1) |
|
|
(803 |
) |
|
|
679 |
|
|
|
|
|
(562 |
) |
|
|
(241 |
) |
|
|
|
|
(480 |
) |
|
|
209 |
|
|
|
96 |
|
|
|
583 |
|
|
|
|
|
(40 |
) |
|
|
19 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ceiling Test Impairments, after tax |
|
|
(2,550 |
) |
|
|
- |
|
|
|
|
|
(1,328 |
) |
|
|
(1,222 |
) |
|
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
|
|
- |
|
|
|
- |
|
Gain (Loss) on Divestitures, after tax |
|
|
11 |
|
|
|
135 |
|
|
|
|
|
1 |
|
|
|
10 |
|
|
|
|
|
(11 |
) |
|
|
2,399 |
|
|
|
135 |
|
|
|
- |
|
|
|
|
|
- |
|
|
|
- |
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|
Production Volumes |
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|
|
|
|
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|
Natural Gas (MMcf/d) |
|
|
1,712 |
|
|
|
2,675 |
|
|
|
|
|
1,568 |
|
|
|
1,857 |
|
|
|
|
|
1,861 |
|
|
|
2,199 |
|
|
|
2,541 |
|
|
|
2,809 |
|
|
|
|
|
2,744 |
|
|
|
2,723 |
|
Oil & NGLs (Mbbls/d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
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|
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|
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|
Oil |
|
|
82.7 |
|
|
|
33.1 |
|
|
|
|
|
86.2 |
|
|
|
79.2 |
|
|
|
|
|
68.8 |
|
|
|
62.1 |
|
|
|
34.2 |
|
|
|
32.1 |
|
|
|
|
|
33.0 |
|
|
|
27.2 |
|
NGLs |
|
|
41.3 |
|
|
|
34.9 |
|
|
|
|
|
41.1 |
|
|
|
41.5 |
|
|
|
|
|
37.6 |
|
|
|
41.9 |
|
|
|
34.0 |
|
|
|
35.8 |
|
|
|
|
|
33.0 |
|
|
|
31.0 |
|
Total Oil & NGLs |
|
|
124.0 |
|
|
|
68.0 |
|
|
|
|
|
127.3 |
|
|
|
120.7 |
|
|
|
|
|
106.4 |
|
|
|
104.0 |
|
|
|
68.2 |
|
|
|
67.9 |
|
|
|
|
|
66.0 |
|
|
|
58.2 |
|
Total Production (MBOE/d) |
|
|
409.3 |
|
|
|
513.8 |
|
|
|
|
|
388.7 |
|
|
|
430.1 |
|
|
|
|
|
416.7 |
|
|
|
470.6 |
|
|
|
491.8 |
|
|
|
536.1 |
|
|
|
|
|
523.4 |
|
|
|
512.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production Mix (%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas |
|
|
70 |
|
|
|
87 |
|
|
|
|
|
67 |
|
|
|
72 |
|
|
|
|
|
74 |
|
|
|
78 |
|
|
|
86 |
|
|
|
87 |
|
|
|
|
|
87 |
|
|
|
89 |
|
Oil & NGLs |
|
|
30 |
|
|
|
13 |
|
|
|
|
|
33 |
|
|
|
28 |
|
|
|
|
|
26 |
|
|
|
22 |
|
|
|
14 |
|
|
|
13 |
|
|
|
|
|
13 |
|
|
|
11 |
|
(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 expense calculated using the estimated annual effective income tax rate as discussed in the Other Operating
|
|
|
|
|
|
|
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
|
|
|
Q2 Report | For the period ended June 30,
2015 |
Results section of this MD&A. Quarterly net earnings are also impacted by acquisition and divestiture transactions, which are 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 second quarter and first six months of 2015, the Company recognized after-tax non-cash ceiling test impairments of $1,328 million and $2,550
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 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 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 June 30, 2015 versus June 30, 2014
Cash Flow of $181 million decreased $475 million in the three months ended June 30, 2015 and was impacted by the following significant items:
|
|
|
Average realized natural gas prices, excluding financial hedges, were $2.37 per Mcf compared to $4.46 per Mcf in 2014 reflecting lower benchmark prices.
Lower realized natural gas prices decreased revenues $285 million. Average realized liquids prices, excluding financial hedges, were $43.83 per bbl compared to $71.23 per bbl in 2014 reflecting lower benchmark prices. Lower realized liquids prices
decreased revenues $208 million. |
|
|
|
Average natural gas production volumes of 1,568 MMcf/d decreased 973 MMcf/d from 2,541 MMcf/d in 2014 primarily due to divestitures, natural declines in the
USA Operations and lower production from Deep Panuke, partially offset by a successful drilling program in Montney. Lower natural gas volumes decreased revenues $408 million. Average oil and NGL production volumes of 127.3 Mbbls/d increased 59.1
Mbbls/d from 68.2 Mbbls/d in 2014 primarily due to acquisitions and successful drilling programs in oil and liquids rich natural gas plays, partially offset by divestitures. Higher oil and NGL volumes increased revenues $271 million.
|
|
|
|
Realized financial hedging gains before tax were $161 million compared to losses of $102 million in 2014. |
|
|
|
Transportation and processing expense decreased $100 million primarily due to divestitures, the lower U.S./Canadian dollar exchange rate and lower production
from Deep Panuke, partially offset by higher liquids volumes in Montney. |
|
|
|
Operating expense increased $31 million primarily due to liquids-weighted acquisitions, partially offset by divestitures, lower non-cash long-term
compensation costs resulting from the decrease in the Encana share price and the lower U.S./Canadian dollar exchange rate. |
|
|
|
Interest expense increased $156 million primarily due to a one-time interest payment of approximately $165 million resulting from the early redemption of
Encanas $700 million 5.90 percent notes due December 1, 2017 and C$750 million 5.80 percent medium-term notes due January 18, 2018. |
|
|
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
|
|
|
Q2 Report | For the period ended June 30, 2015
|
Operating Loss in the second quarter of 2015 was $167 million compared to Operating Earnings of $171
million in 2014 primarily due to the items discussed in the Cash Flow section. Operating Loss for the second quarter of 2015 was also impacted by a higher foreign exchange loss on settlements and the revaluation of other monetary assets and
liabilities and deferred tax.
Net Loss Attributable to Common Shareholders in the second quarter of 2015 was $1,610 million compared to Net
Earnings Attributable to Common Shareholders of $271 million in 2014 primarily due to an after-tax non-cash ceiling test impairment and the items discussed in the Cash Flow and Operating Earnings sections. Net Loss for the second quarter of 2015 was
also impacted by after-tax unrealized hedging losses, a lower after-tax gain on divestitures, a lower after-tax non-operating foreign exchange gain and deferred tax.
Six months ended June 30, 2015 versus June 30, 2014
Cash Flow of $676 million decreased $1,074 million in the six months ended June 30, 2015 and was impacted by the following significant items:
|
|
|
Average realized natural gas prices, excluding financial hedges, were $3.00 per Mcf compared to $5.46 per Mcf in 2014 reflecting lower benchmark prices.
Lower realized natural gas prices decreased revenues $735 million. Average realized liquids prices, excluding financial hedges, were $39.14 per bbl compared to $70.24 per bbl in 2014 reflecting lower benchmark prices. Lower realized liquids prices
decreased revenues $416 million. |
|
|
|
Average natural gas production volumes of 1,712 MMcf/d decreased 963 MMcf/d from 2,675 MMcf/d in 2014 primarily due to divestitures, natural declines in the
USA Operations and lower production from Deep Panuke, partially offset by a successful drilling program in Montney. Lower natural gas volumes decreased revenues $980 million. Average oil and NGL production volumes of 124.0 Mbbls/d increased 56.0
Mbbls/d from 68.0 Mbbls/d in 2014 primarily due to acquisitions and successful drilling programs in oil and liquids rich natural gas plays, partially offset by divestitures. Higher oil and NGL volumes increased revenues $427 million.
|
|
|
|
Realized financial hedging gains before tax were $401 million compared to losses of $243 million in 2014. |
|
|
|
Transportation and processing expense decreased $139 million primarily due to divestitures, the lower U.S./Canadian dollar exchange rate and lower production
from Deep Panuke, partially offset by higher liquids volumes in Montney. |
|
|
|
Interest expense increased $134 million primarily due to a one-time interest payment of approximately $165 million resulting from the early redemption of
Encanas $700 million 5.90 percent notes due December 1, 2017 and C$750 million 5.80 percent medium-term notes due January 18, 2018. |
Operating Loss in the first six months of 2015 was $148 million compared to Operating Earnings of $686 million in 2014 primarily due to the items
discussed in the Cash Flow section. Operating Loss for the first six months of 2015 was also impacted by a higher foreign exchange loss on settlements and the revaluation of other monetary assets and liabilities and deferred tax.
Net Loss Attributable to Common Shareholders in the first six months of 2015 was $3,317 million compared to Net Earnings Attributable to Common
Shareholders of $387 million in 2014 primarily due to after-tax non-cash ceiling test impairments and the items discussed in the Cash Flow and Operating Earnings sections. Net Loss for the first six months of 2015 was also impacted by a higher
after-tax non-operating foreign exchange loss, a lower after-tax gain on divestitures, higher after-tax unrealized hedging losses and deferred tax.
|
|
|
|
|
|
|
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
|
|
|
Q2 Report | For the period ended June 30,
2015 |
Prices and Foreign Exchange Rates
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six months ended June 30 |
|
|
|
|
2015 |
|
|
|
|
2014 |
|
|
|
|
2013 |
|
(average for the period) |
|
2015 |
|
|
2014 |
|
|
|
|
Q2 |
|
|
Q1 |
|
|
|
|
Q4 |
|
|
Q3 |
|
|
Q2 |
|
|
Q1 |
|
|
|
|
Q4 |
|
|
Q3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Encana Realized Pricing |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Including Hedging |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas ($/Mcf) |
|
$ |
4.20 |
|
|
$ |
4.99 |
|
|
|
|
$ |
3.52 |
|
|
$ |
4.78 |
|
|
|
|
$ |
4.16 |
|
|
$ |
4.03 |
|
|
$ |
4.08 |
|
|
$ |
5.82 |
|
|
|
|
$ |
4.34 |
|
|
$ |
4.00 |
|
Oil & NGLs ($/bbl) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
|
49.80 |
|
|
|
88.00 |
|
|
|
|
|
53.08 |
|
|
|
46.17 |
|
|
|
|
|
80.38 |
|
|
|
90.22 |
|
|
|
89.55 |
|
|
|
86.34 |
|
|
|
|
|
85.39 |
|
|
|
90.42 |
|
NGLs |
|
|
23.10 |
|
|
|
51.64 |
|
|
|
|
|
24.28 |
|
|
|
21.92 |
|
|
|
|
|
40.87 |
|
|
|
48.76 |
|
|
|
49.39 |
|
|
|
53.79 |
|
|
|
|
|
48.59 |
|
|
|
46.35 |
|
Total Oil & NGLs |
|
|
40.91 |
|
|
|
69.36 |
|
|
|
|
|
43.78 |
|
|
|
37.83 |
|
|
|
|
|
66.40 |
|
|
|
73.50 |
|
|
|
69.53 |
|
|
|
69.19 |
|
|
|
|
|
67.01 |
|
|
|
66.95 |
|
Total ($/BOE) |
|
|
29.94 |
|
|
|
35.14 |
|
|
|
|
|
28.53 |
|
|
|
31.24 |
|
|
|
|
|
35.55 |
|
|
|
35.06 |
|
|
|
30.75 |
|
|
|
39.22 |
|
|
|
|
|
31.23 |
|
|
|
28.85 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Excluding Hedging |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas ($/Mcf) |
|
|
3.00 |
|
|
|
5.46 |
|
|
|
|
|
2.37 |
|
|
|
3.53 |
|
|
|
|
|
3.94 |
|
|
|
3.88 |
|
|
|
4.46 |
|
|
|
6.37 |
|
|
|
|
|
3.69 |
|
|
|
3.26 |
|
Oil & NGLs ($/bbl) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
|
47.15 |
|
|
|
89.80 |
|
|
|
|
|
53.15 |
|
|
|
40.53 |
|
|
|
|
|
66.38 |
|
|
|
90.18 |
|
|
|
92.93 |
|
|
|
86.43 |
|
|
|
|
|
82.54 |
|
|
|
96.09 |
|
NGLs |
|
|
23.10 |
|
|
|
51.64 |
|
|
|
|
|
24.28 |
|
|
|
21.92 |
|
|
|
|
|
40.87 |
|
|
|
48.76 |
|
|
|
49.39 |
|
|
|
53.79 |
|
|
|
|
|
48.59 |
|
|
|
46.35 |
|
Total Oil & NGLs |
|
|
39.14 |
|
|
|
70.24 |
|
|
|
|
|
43.83 |
|
|
|
34.13 |
|
|
|
|
|
57.35 |
|
|
|
73.48 |
|
|
|
71.23 |
|
|
|
69.23 |
|
|
|
|
|
65.58 |
|
|
|
69.60 |
|
Total ($/BOE) |
|
|
24.38 |
|
|
|
37.70 |
|
|
|
|
|
23.90 |
|
|
|
24.82 |
|
|
|
|
|
32.25 |
|
|
|
34.36 |
|
|
|
32.93 |
|
|
|
42.12 |
|
|
|
|
|
27.63 |
|
|
|
25.23 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Price Benchmarks |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NYMEX ($/MMBtu) |
|
|
2.81 |
|
|
|
4.80 |
|
|
|
|
|
2.64 |
|
|
|
2.98 |
|
|
|
|
|
4.00 |
|
|
|
4.06 |
|
|
|
4.67 |
|
|
|
4.94 |
|
|
|
|
|
3.60 |
|
|
|
3.58 |
|
AECO (C$/Mcf) |
|
|
2.81 |
|
|
|
4.72 |
|
|
|
|
|
2.67 |
|
|
|
2.95 |
|
|
|
|
|
4.01 |
|
|
|
4.22 |
|
|
|
4.68 |
|
|
|
4.76 |
|
|
|
|
|
3.15 |
|
|
|
2.82 |
|
Algonquin City Gate ($/MMBtu) |
|
|
6.80 |
|
|
|
12.21 |
|
|
|
|
|
2.24 |
|
|
|
11.41 |
|
|
|
|
|
4.99 |
|
|
|
2.97 |
|
|
|
4.23 |
|
|
|
20.28 |
|
|
|
|
|
7.80 |
|
|
|
3.98 |
|
Basis Differential ($/MMBtu) AECO/NYMEX |
|
|
0.53 |
|
|
|
0.50 |
|
|
|
|
|
0.50 |
|
|
|
0.57 |
|
|
|
|
|
0.44 |
|
|
|
0.16 |
|
|
|
0.40 |
|
|
|
0.60 |
|
|
|
|
|
0.59 |
|
|
|
0.89 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil Price Benchmarks |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
West Texas Intermediate (WTI) ($/bbl) |
|
|
53.29 |
|
|
|
100.84 |
|
|
|
|
|
57.94 |
|
|
|
48.64 |
|
|
|
|
|
73.15 |
|
|
|
97.17 |
|
|
|
102.99 |
|
|
|
98.68 |
|
|
|
|
|
97.46 |
|
|
|
105.81 |
|
Edmonton Light Sweet (C$/bbl) |
|
|
59.82 |
|
|
|
102.72 |
|
|
|
|
|
67.71 |
|
|
|
51.94 |
|
|
|
|
|
75.69 |
|
|
|
97.16 |
|
|
|
105.61 |
|
|
|
99.83 |
|
|
|
|
|
86.58 |
|
|
|
103.65 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign Exchange |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average U.S./Canadian Dollar Exchange Rate |
|
|
0.810 |
|
|
|
0.912 |
|
|
|
|
|
0.813 |
|
|
|
0.806 |
|
|
|
|
|
0.881 |
|
|
|
0.918 |
|
|
|
0.917 |
|
|
|
0.906 |
|
|
|
|
|
0.953 |
|
|
|
0.963 |
|
Encanas financial results are influenced by fluctuations in commodity prices, price differentials and the
U.S./Canadian dollar exchange rate. In the second quarter and first six months of 2015, Encanas average realized natural gas price, excluding hedging, reflected lower benchmark prices compared to 2014. Hedging activities contributed $1.15 per
Mcf to Encanas average realized natural gas price in the second quarter of 2015 and $1.20 per Mcf in the first six months of 2015. The average realized natural gas price for production from Deep Panuke was $9.40 per Mcf in the first six months
of 2015 compared to $11.31 per Mcf in 2014 and increased Encanas average realized natural gas price $0.43 per Mcf in the first six months of 2015 compared to $0.60 per Mcf in 2014.
In the second quarter and first six months of 2015, Encanas average realized oil and NGL prices, excluding hedging, reflected lower benchmark
prices compared to 2014. Hedging activities reduced Encanas average realized oil price $0.07 per bbl in the second quarter of 2015 and contributed $2.65 per bbl in the first six months of 2015.
As a means of managing commodity price volatility and its impact on cash flows, Encana enters into various financial hedge agreements. Unsettled
derivative financial contracts are recorded at the date of the financial statements based on the fair value of the contracts. Changes in fair value result from volatility in forward curves of
|
|
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
|
|
|
Q2 Report | For the period ended June 30, 2015
|
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.
At June 30, 2015, Encana has hedged approximately
1,000 MMcf/d of expected July to December 2015 natural gas production using NYMEX fixed price contracts at an average price of $4.29 per Mcf. In addition, Encana has hedged approximately 59.4 Mbbls/d of expected July to December 2015 oil production
using WTI fixed price contracts at an average price of $61.96 per bbl and approximately 38.0 Mbbls/d of expected 2016 oil production at an average price of $62.83 per bbl.
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.
Foreign Exchange
As disclosed in the Prices and Foreign Exchange Rates table, the average U.S./Canadian dollar exchange rate decreased 0.104 in the second quarter of 2015
compared to the second quarter of 2014 and 0.102 in the first six months of 2015 compared to the first six 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 June 30 |
|
|
|
|
Six months ended June 30 |
|
|
|
$ millions |
|
|
$/BOE |
|
|
|
|
$ millions |
|
|
$/BOE |
|
|
|
|
|
|
|
Increase (Decrease) in: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital Investment |
|
|
$ (40) |
|
|
|
|
|
|
|
|
|
$ (72) |
|
|
|
|
|
Transportation and Processing
Expense |
|
|
(25) |
|
|
|
$ (0.72) |
|
|
|
|
|
(49) |
|
|
|
$ (0.66) |
|
Operating Expense |
|
|
(9) |
|
|
|
(0.25) |
|
|
|
|
|
(19) |
|
|
|
(0.25) |
|
Administrative Expense |
|
|
(8) |
|
|
|
(0.23) |
|
|
|
|
|
(16) |
|
|
|
(0.21) |
|
Depreciation, Depletion and Amortization |
|
|
(19) |
|
|
|
(0.53) |
|
|
|
|
|
(38) |
|
|
|
(0.51) |
|
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
second quarter of 2015. The price sensitivities below are based on business conditions, transactions and production volumes during the second 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 |
|
|
|
|
|
$ 25 |
|
|
|
|
|
$ 17 |
|
WTI Oil Price |
|
+/- $ |
10.00/bbl |
|
|
|
|
|
45 |
|
|
|
|
|
30 |
|
(1) |
Assumes only one variable changes while all other variables are held constant. |
|
|
|
|
|
|
|
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
|
|
|
Q2 Report | For the period ended June 30,
2015 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30 |
|
|
|
|
Six months ended June 30 |
|
($ millions) |
|
2015 |
|
|
2014 |
|
|
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
|
Canadian Operations |
|
$ |
114 |
|
|
$ |
350 |
|
|
|
|
$ |
265 |
|
|
$ |
631 |
|
USA Operations |
|
|
628 |
|
|
|
206 |
|
|
|
|
|
1,211 |
|
|
|
432 |
|
Market Optimization |
|
|
- |
|
|
|
1 |
|
|
|
|
|
- |
|
|
|
2 |
|
Corporate & Other |
|
|
1 |
|
|
|
3 |
|
|
|
|
|
3 |
|
|
|
6 |
|
Capital Investment |
|
|
743 |
|
|
|
560 |
|
|
|
|
|
1,479 |
|
|
|
1,071 |
|
Acquisitions |
|
|
3 |
|
|
|
2,923 |
|
|
|
|
|
38 |
|
|
|
2,946 |
|
Divestitures |
|
|
(143 |
) |
|
|
(2,271 |
) |
|
|
|
|
(1,016 |
) |
|
|
(2,318 |
) |
Net Acquisitions & (Divestitures) |
|
|
(140 |
) |
|
|
652 |
|
|
|
|
|
(978 |
) |
|
|
628 |
|
Net Capital Investment |
|
$ |
603 |
|
|
$ |
1,212 |
|
|
|
|
$ |
501 |
|
|
$ |
1,699 |
|
|
|
|
|
|
|
Capital Investment by Play |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30 |
|
|
|
|
Six months ended June 30 |
|
($ millions) |
|
2015 |
|
|
2014 |
|
|
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
|
Canadian Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Montney (1) |
|
$ |
48 |
|
|
$ |
210 |
|
|
|
|
$ |
127 |
|
|
$ |
418 |
|
Duvernay |
|
|
57 |
|
|
|
81 |
|
|
|
|
|
127 |
|
|
|
152 |
|
Other Upstream Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wheatland (2) |
|
|
4 |
|
|
|
12 |
|
|
|
|
|
4 |
|
|
|
30 |
|
Bighorn |
|
|
- |
|
|
|
10 |
|
|
|
|
|
- |
|
|
|
19 |
|
Deep Panuke |
|
|
1 |
|
|
|
2 |
|
|
|
|
|
3 |
|
|
|
(1 |
) |
Other and emerging (1) |
|
|
4 |
|
|
|
35 |
|
|
|
|
|
4 |
|
|
|
13 |
|
Total Canadian Operations |
|
$ |
114 |
|
|
$ |
350 |
|
|
|
|
$ |
265 |
|
|
$ |
631 |
|
|
|
|
|
|
|
USA Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Eagle Ford |
|
$ |
175 |
|
|
$ |
12 |
|
|
|
|
$ |
372 |
|
|
$ |
12 |
|
Permian |
|
|
325 |
|
|
|
- |
|
|
|
|
|
542 |
|
|
|
- |
|
DJ Basin |
|
|
56 |
|
|
|
69 |
|
|
|
|
|
144 |
|
|
|
128 |
|
San Juan |
|
|
23 |
|
|
|
50 |
|
|
|
|
|
59 |
|
|
|
102 |
|
Other Upstream Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Piceance |
|
|
3 |
|
|
|
5 |
|
|
|
|
|
6 |
|
|
|
26 |
|
Haynesville |
|
|
10 |
|
|
|
(5 |
) |
|
|
|
|
12 |
|
|
|
33 |
|
Jonah |
|
|
- |
|
|
|
16 |
|
|
|
|
|
- |
|
|
|
27 |
|
East Texas |
|
|
- |
|
|
|
- |
|
|
|
|
|
- |
|
|
|
10 |
|
Other and emerging |
|
|
36 |
|
|
|
59 |
|
|
|
|
|
76 |
|
|
|
94 |
|
Total USA Operations |
|
$ |
628 |
|
|
$ |
206 |
|
|
|
|
$ |
1,211 |
|
|
$ |
432 |
|
Capital Investment Growth Assets
(1) |
|
$ |
700 |
|
|
$ |
449 |
|
|
|
|
$ |
1,413 |
|
|
$ |
859 |
|
(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. |
Growth assets includes Encanas top four
strategic assets Montney, Duvernay, Eagle Ford and Permian as well as the DJ Basin, San Juan and the Tuscaloosa Marine Shale (TMS), which represent additional high-quality investment opportunities. 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 TMS, which is reported within Other and emerging in the USA Operations. For
the second quarter and first six months of 2015, capital investment in the TMS was $16 million and $42 million, respectively (2014 $27 million and $47 million, respectively).
Capital investment associated with the Clearwater lands transferred to PrairieSky Royalty Ltd. (PrairieSky) was included in Encanas
Wheatland play until September 25, 2014, after which Encana no longer held an interest in PrairieSky.
|
|
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
|
|
|
Q2 Report | For the period ended June 30, 2015
|
Capital Investment
Capital investment during the first six months of 2015 was $1,479 million compared to $1,071 million in 2014. The Companys disciplined capital
spending focused on investment in its growth assets, as well as executing drilling programs with joint venture partners. During the first six months of 2015, capital spending in the Companys growth assets totaled $1,413 million (2014
$859 million), representing approximately 96 percent (2014 80 percent) of the Companys capital investment, with $1,168 million (2014 $582 million) spent on Encanas top four strategic assets.
Divestitures
Divestitures in the first six months of 2015 were $879 million in the Canadian Operations and $84 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. Immediately following the sale, Encana retained a
working interest in approximately 1.1 million net acres in the area. The Canadian Operations also included approximately C$454 million ($358 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 can be found in Note 16 to the Interim Condensed Consolidated Financial Statements.
Divestitures in the first six months of 2014 were $121 million in the Canadian Operations and $2,170 million in the USA Operations. The USA Operations
primarily included approximately $1.6 billion, after closing adjustments, for the sale of the Jonah properties and approximately $427 million for the sale of certain properties in East Texas.
Amounts received from the divestiture transactions above have been deducted from the respective Canadian and U.S. full cost pools, except for the sale
of the Jonah properties. The proved reserves associated with the Jonah divestiture exceeded 25 percent of Encanas proved reserves in the U.S. cost centre. The carrying amount of the assets was deducted from the full cost pool and the remainder
of the proceeds was recognized as a gain on sale of approximately $212 million, before tax. Goodwill of $68 million was allocated to the divestiture.
Acquisitions
Acquisitions in the first six months of 2014 were $2,944 million in the USA Operations which primarily related to the acquisition of Eagle Ford.
2014 Capital Transactions
The significant acquisition and divestiture transactions below, which occurred during 2014, have impacted the Companys production volume and
operating cash flow variances for the second quarter and first six months of 2015. A comprehensive discussion of these transactions is included in the annual MD&A for the year ended December 31, 2014.
|
|
|
|
|
|
|
Transaction |
|
Location |
|
Closing Date |
|
Canadian Operations |
|
|
|
|
|
|
Divestiture of Encanas remaining investment in PrairieSky (1),
(2) |
|
Alberta |
|
|
September 26, 2014 |
|
Sale of Bighorn assets |
|
Alberta |
|
|
September 30, 2014 |
|
|
|
|
USA Operations |
|
|
|
|
|
|
Sale of Jonah properties |
|
Wyoming |
|
|
May 12, 2014 |
|
Sale of East Texas properties |
|
Texas |
|
|
June 19, 2014 |
|
Acquisition of properties in the Eagle Ford shale formation |
|
Texas |
|
|
June 20, 2014 |
|
Acquisition of Athlon Energy Inc. with assets in the Permian Basin (1) |
|
Texas |
|
|
November 13, 2014 |
|
(1) |
Transactions involved the disposition or acquisition of common shares and, therefore, were not part of the Companys net acquisition and divestiture activity for 2014. |
(2) |
Encana completed the initial public offering of PrairieSky on May 29, 2014. |
|
|
|
|
|
|
|
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
|
|
|
Q2 Report | For the period ended June 30,
2015 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30 |
|
|
|
Six months
ended June 30 |
(average daily, after royalties) |
|
2015 |
|
2014 |
|
|
|
2015 |
|
2014 |
|
|
|
|
|
|
Natural Gas (MMcf/d) |
|
|
|
1,568 |
|
|
|
|
2,541 |
|
|
|
|
|
|
1,712 |
|
|
|
|
2,675 |
|
|
|
|
|
|
|
Oil (Mbbls/d) |
|
|
|
86.2 |
|
|
|
|
34.2 |
|
|
|
|
|
|
82.7 |
|
|
|
|
33.1 |
|
NGLs (Mbbls/d) |
|
|
|
41.1 |
|
|
|
|
34.0 |
|
|
|
|
|
|
41.3 |
|
|
|
|
34.9 |
|
Total Oil & NGLs (Mbbls/d) |
|
|
|
127.3 |
|
|
|
|
68.2 |
|
|
|
|
|
|
124.0 |
|
|
|
|
68.0 |
|
Total Production (MBOE/d) |
|
|
|
388.7 |
|
|
|
|
491.8 |
|
|
|
|
|
|
409.3 |
|
|
|
|
513.8 |
|
|
|
|
|
|
|
Production Mix (%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas |
|
|
|
67 |
|
|
|
|
86 |
|
|
|
|
|
|
70 |
|
|
|
|
87 |
|
Oil & NGLs |
|
|
|
33 |
|
|
|
|
14 |
|
|
|
|
|
|
30 |
|
|
|
|
13 |
|
Production Volumes by Play
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30 |
|
Six months ended June 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) |
|
|
685 |
|
|
|
604 |
|
|
|
|
|
21.6 |
|
|
|
13.3 |
|
|
|
|
|
701 |
|
|
|
612 |
|
|
|
|
|
22.5 |
|
|
|
14.8 |
|
Duvernay |
|
|
17 |
|
|
|
9 |
|
|
|
|
|
3.0 |
|
|
|
1.8 |
|
|
|
|
|
17 |
|
|
|
9 |
|
|
|
|
|
2.9 |
|
|
|
1.6 |
|
Other Upstream Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wheatland (2) |
|
|
76 |
|
|
|
305 |
|
|
|
|
|
1.2 |
|
|
|
11.3 |
|
|
|
|
|
94 |
|
|
|
314 |
|
|
|
|
|
1.5 |
|
|
|
11.3 |
|
Bighorn |
|
|
- |
|
|
|
230 |
|
|
|
|
|
- |
|
|
|
11.0 |
|
|
|
|
|
2 |
|
|
|
238 |
|
|
|
|
|
- |
|
|
|
11.5 |
|
Deep Panuke |
|
|
32 |
|
|
|
243 |
|
|
|
|
|
- |
|
|
|
- |
|
|
|
|
|
107 |
|
|
|
248 |
|
|
|
|
|
- |
|
|
|
- |
|
Other and emerging (1) |
|
|
71 |
|
|
|
72 |
|
|
|
|
|
0.5 |
|
|
|
- |
|
|
|
|
|
83 |
|
|
|
95 |
|
|
|
|
|
0.1 |
|
|
|
- |
|
Total Canadian Operations |
|
|
881 |
|
|
|
1,463 |
|
|
|
|
|
26.3 |
|
|
|
37.4 |
|
|
|
|
|
1,004 |
|
|
|
1,516 |
|
|
|
|
|
27.0 |
|
|
|
39.2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
USA Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Eagle Ford |
|
|
36 |
|
|
|
5 |
|
|
|
|
|
39.8 |
|
|
|
5.0 |
|
|
|
|
|
36 |
|
|
|
2 |
|
|
|
|
|
37.9 |
|
|
|
2.5 |
|
Permian |
|
|
38 |
|
|
|
- |
|
|
|
|
|
29.5 |
|
|
|
- |
|
|
|
|
|
36 |
|
|
|
- |
|
|
|
|
|
28.1 |
|
|
|
- |
|
DJ Basin |
|
|
55 |
|
|
|
43 |
|
|
|
|
|
15.3 |
|
|
|
10.1 |
|
|
|
|
|
52 |
|
|
|
42 |
|
|
|
|
|
14.8 |
|
|
|
10.3 |
|
San Juan |
|
|
15 |
|
|
|
7 |
|
|
|
|
|
6.4 |
|
|
|
3.9 |
|
|
|
|
|
14 |
|
|
|
7 |
|
|
|
|
|
6.6 |
|
|
|
3.3 |
|
Other Upstream Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Piceance |
|
|
324 |
|
|
|
407 |
|
|
|
|
|
3.7 |
|
|
|
5.3 |
|
|
|
|
|
333 |
|
|
|
421 |
|
|
|
|
|
3.7 |
|
|
|
5.4 |
|
Haynesville |
|
|
204 |
|
|
|
365 |
|
|
|
|
|
- |
|
|
|
- |
|
|
|
|
|
217 |
|
|
|
348 |
|
|
|
|
|
- |
|
|
|
- |
|
Jonah |
|
|
- |
|
|
|
124 |
|
|
|
|
|
- |
|
|
|
2.5 |
|
|
|
|
|
- |
|
|
|
203 |
|
|
|
|
|
- |
|
|
|
3.6 |
|
East Texas |
|
|
- |
|
|
|
97 |
|
|
|
|
|
- |
|
|
|
1.0 |
|
|
|
|
|
- |
|
|
|
105 |
|
|
|
|
|
- |
|
|
|
1.1 |
|
Other and emerging |
|
|
15 |
|
|
|
30 |
|
|
|
|
|
6.3 |
|
|
|
3.0 |
|
|
|
|
|
20 |
|
|
|
31 |
|
|
|
|
|
5.9 |
|
|
|
2.6 |
|
Total USA Operations |
|
|
687 |
|
|
|
1,078 |
|
|
|
|
|
101.0 |
|
|
|
30.8 |
|
|
|
|
|
708 |
|
|
|
1,159 |
|
|
|
|
|
97.0 |
|
|
|
28.8 |
|
Total Production Volumes |
|
|
1,568 |
|
|
|
2,541 |
|
|
|
|
|
127.3 |
|
|
|
68.2 |
|
|
|
|
|
1,712 |
|
|
|
2,675 |
|
|
|
|
|
124.0 |
|
|
|
68.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Production Volumes Growth Assets
(1) |
|
|
846 |
|
|
|
668 |
|
|
|
|
|
121.3 |
|
|
|
35.3 |
|
|
|
|
|
856 |
|
|
|
672 |
|
|
|
|
|
117.8 |
|
|
|
33.4 |
|
|
(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$ |
|
|
|
Q2 Report | For the period ended June 30, 2015
|
Growth assets includes Encanas top four strategic assets Montney, Duvernay, Eagle Ford and
Permian as well as the DJ Basin, San Juan and the TMS, which represent additional high-quality investment opportunities. 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 second quarter of 2015, average natural gas production volumes of 1,568 MMcf/d decreased 973 MMcf/d from 2014. In the first six months of 2015,
average natural gas production volumes of 1,712 MMcf/d decreased 963 MMcf/d from 2014.
The USA Operations volumes were lower in the second
quarter and first six months of 2015 primarily due to the sales of the Jonah and East Texas properties in the second quarter of 2014 and natural declines in Haynesville and Piceance. The Canadian Operations volumes were lower in the second quarter
and first six months of 2015 primarily due to the sale of the Bighorn assets in the third quarter of 2014, the sale of certain assets included in Wheatland in January 2015 and production declines at Deep Panuke due to the implementation of a
seasonal operating strategy and a higher water production rate, partially offset by a successful drilling program in Montney.
Oil and NGL
Production Volumes
In the second quarter of 2015, average oil and NGL production volumes of 127.3 Mbbls/d increased 59.1 Mbbls/d from 2014.
In the first six months of 2015, average oil and NGL production volumes of 124.0 Mbbls/d increased 56.0 Mbbls/d from 2014.
The USA Operations
volumes were higher in the second quarter and first six months of 2015 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 Eagle Ford,
Permian, the DJ Basin, the TMS and San Juan, partially offset by the sales of the Jonah and East Texas properties in the second quarter of 2014. The Canadian Operations volumes were lower in the second quarter and first six 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$ |
|
Q2 Report | For the period ended June 30,
2015 |
Canadian Operations
Operating Cash Flow
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30 |
|
|
|
Natural Gas |
|
|
|
|
Oil & NGLs |
|
|
|
|
Total (1) |
|
($ millions) |
|
2015 |
|
|
2014 |
|
|
|
|
2015 |
|
|
2014 |
|
|
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
|
|
|
|
Revenues, Net of Royalties, excluding Hedging |
|
$ |
193 |
|
|
$ |
569 |
|
|
|
|
$ |
91 |
|
|
$ |
227 |
|
|
|
|
$ |
286 |
|
|
$ |
803 |
|
Realized Financial Hedging Gain (Loss) |
|
|
106 |
|
|
|
(44 |
) |
|
|
|
|
(5 |
) |
|
|
(5 |
) |
|
|
|
|
101 |
|
|
|
(49 |
) |
Revenues, Net of Royalties |
|
|
299 |
|
|
|
525 |
|
|
|
|
|
86 |
|
|
|
222 |
|
|
|
|
|
387 |
|
|
|
754 |
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and mineral taxes |
|
|
- |
|
|
|
- |
|
|
|
|
|
- |
|
|
|
4 |
|
|
|
|
|
- |
|
|
|
4 |
|
Transportation and processing |
|
|
158 |
|
|
|
209 |
|
|
|
|
|
13 |
|
|
|
16 |
|
|
|
|
|
171 |
|
|
|
225 |
|
Operating |
|
|
40 |
|
|
|
72 |
|
|
|
|
|
5 |
|
|
|
4 |
|
|
|
|
|
45 |
|
|
|
78 |
|
Operating Cash Flow |
|
$ |
101 |
|
|
$ |
244 |
|
|
|
|
$ |
68 |
|
|
$ |
198 |
|
|
|
|
$ |
171 |
|
|
$ |
447 |
|
Production Volumes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30 |
|
|
|
Natural Gas
(MMcf/d) |
|
|
|
|
Oil & NGLs
(Mbbls/d) |
|
|
|
|
Total
(MBOE/d) |
|
|
|
2015 |
|
|
2014 |
|
|
|
|
2015 |
|
|
2014 |
|
|
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
|
|
|
|
Production Volumes After Royalties |
|
|
881 |
|
|
|
1,463 |
|
|
|
|
|
26.3 |
|
|
|
37.4 |
|
|
|
|
|
173.2 |
|
|
|
281.4 |
|
Operating Netback (2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30 |
|
|
|
Natural Gas
($/Mcf) |
|
|
|
|
Oil & NGLs
($/bbl) |
|
|
|
|
Total
($/BOE) |
|
|
|
2015 |
|
|
2014 |
|
|
|
|
2015 |
|
|
2014 |
|
|
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
|
|
|
|
Revenues, Net of Royalties, excluding Hedging |
|
$ |
2.39 |
|
|
$ |
4.27 |
|
|
|
|
$ |
38.57 |
|
|
$ |
66.13 |
|
|
|
|
$ |
18.05 |
|
|
$ |
31.02 |
|
Realized Financial Hedging Gain (Loss) |
|
|
1.32 |
|
|
|
(0.33 |
) |
|
|
|
|
(2.21 |
) |
|
|
(1.22 |
) |
|
|
|
|
6.39 |
|
|
|
(1.89 |
) |
Revenues, Net of Royalties |
|
|
3.71 |
|
|
|
3.94 |
|
|
|
|
|
36.36 |
|
|
|
64.91 |
|
|
|
|
|
24.44 |
|
|
|
29.13 |
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and mineral taxes |
|
|
- |
|
|
|
- |
|
|
|
|
|
- |
|
|
|
1.12 |
|
|
|
|
|
- |
|
|
|
0.16 |
|
Transportation and processing |
|
|
1.97 |
|
|
|
1.57 |
|
|
|
|
|
5.46 |
|
|
|
4.60 |
|
|
|
|
|
10.85 |
|
|
|
8.76 |
|
Operating |
|
|
0.49 |
|
|
|
0.55 |
|
|
|
|
|
1.91 |
|
|
|
1.06 |
|
|
|
|
|
2.80 |
|
|
|
2.98 |
|
Operating Netback |
|
$ |
1.25 |
|
|
$ |
1.82 |
|
|
|
|
$ |
28.99 |
|
|
$ |
58.13 |
|
|
|
|
$ |
10.79 |
|
|
$ |
17.23 |
|
|
(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$ |
|
|
|
Q2 Report | For the period ended June 30, 2015
|
Three months ended June 30, 2015 versus June 30, 2014
Operating Cash Flow of $171 million decreased $276 million and was impacted by the following significant items:
|
|
|
Lower natural gas prices reflected lower benchmark prices, which decreased revenues $148 million. Lower liquids prices reflected lower benchmark prices,
which decreased revenues $68 million. |
|
|
|
Average natural gas production volumes of 881 MMcf/d were lower by 582 MMcf/d, which decreased revenues $228 million. Average oil and NGL production volumes
of 26.3 Mbbls/d were lower by 11.1 Mbbls/d, which decreased revenues $68 million. Changes in production volumes are discussed in the Production Volumes section of this MD&A. |
|
|
|
Realized financial hedging gains were $101 million compared to losses of $49 million in 2014. |
|
|
|
Transportation and processing expense decreased $54 million primarily due to the sale of the Bighorn assets in the third quarter of 2014, the lower
U.S./Canadian dollar exchange rate and production declines at Deep Panuke, partially offset by higher liquids volumes in Montney. |
|
|
|
Operating expense decreased $33 million primarily due to the sale of certain assets included in Wheatland in January 2015, the sale of the Bighorn assets in
the third quarter of 2014, the lower U.S./Canadian dollar exchange rate and lower long-term compensation costs due to the decrease in the Encana share price. |
|
|
|
|
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
|
Q2 Report | For the period ended June 30,
2015 |
Operating Cash Flow
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six months ended June 30 |
|
|
|
Natural Gas |
|
|
|
|
Oil & NGLs |
|
|
|
|
Total (1) |
|
($ millions) |
|
2015 |
|
|
2014 |
|
|
|
|
2015 |
|
|
2014 |
|
|
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
|
|
|
|
Revenues, Net of Royalties, excluding Hedging |
|
$ |
589 |
|
|
$ |
1,586 |
|
|
|
|
$ |
168 |
|
|
$ |
472 |
|
|
|
|
$ |
762 |
|
|
$ |
2,071 |
|
Realized Financial Hedging Gain (Loss) |
|
|
260 |
|
|
|
(119 |
) |
|
|
|
|
(3 |
) |
|
|
(5 |
) |
|
|
|
|
257 |
|
|
|
(124 |
) |
Revenues, Net of Royalties |
|
|
849 |
|
|
|
1,467 |
|
|
|
|
|
165 |
|
|
|
467 |
|
|
|
|
|
1,019 |
|
|
|
1,947 |
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and mineral taxes |
|
|
- |
|
|
|
2 |
|
|
|
|
|
- |
|
|
|
7 |
|
|
|
|
|
- |
|
|
|
9 |
|
Transportation and processing |
|
|
321 |
|
|
|
410 |
|
|
|
|
|
27 |
|
|
|
30 |
|
|
|
|
|
348 |
|
|
|
440 |
|
Operating |
|
|
76 |
|
|
|
156 |
|
|
|
|
|
11 |
|
|
|
10 |
|
|
|
|
|
87 |
|
|
|
170 |
|
Operating Cash Flow |
|
$ |
452 |
|
|
$ |
899 |
|
|
|
|
$ |
127 |
|
|
$ |
420 |
|
|
|
|
$ |
584 |
|
|
$ |
1,328 |
|
Production Volumes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six months ended June 30 |
|
|
|
Natural Gas
(MMcf/d) |
|
|
|
|
Oil & NGLs
(Mbbls/d) |
|
|
|
|
Total
(MBOE/d) |
|
|
|
2015 |
|
|
2014 |
|
|
|
|
2015 |
|
|
2014 |
|
|
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
|
|
|
|
Production Volumes After Royalties |
|
|
1,004 |
|
|
|
1,516 |
|
|
|
|
|
27.0 |
|
|
|
39.2 |
|
|
|
|
|
194.4 |
|
|
|
291.8 |
|
Operating Netback (2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six months ended June 30 |
|
|
|
Natural Gas
($/Mcf) |
|
|
|
|
Oil & NGLs
($/bbl) |
|
|
|
|
Total
($/BOE) |
|
|
|
2015 |
|
|
2014 |
|
|
|
|
2015 |
|
|
2014 |
|
|
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
|
|
|
|
Revenues, Net of Royalties, excluding Hedging |
|
$ |
3.23 |
|
|
$ |
5.77 |
|
|
|
|
$ |
34.53 |
|
|
$ |
66.25 |
|
|
|
|
$ |
21.50 |
|
|
$ |
38.85 |
|
Realized Financial Hedging Gain (Loss) |
|
|
1.43 |
|
|
|
(0.43 |
) |
|
|
|
|
(0.68 |
) |
|
|
(0.63 |
) |
|
|
|
|
7.30 |
|
|
|
(2.35 |
) |
Revenues, Net of Royalties |
|
|
4.66 |
|
|
|
5.34 |
|
|
|
|
|
33.85 |
|
|
|
65.62 |
|
|
|
|
|
28.80 |
|
|
|
36.50 |
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and mineral taxes |
|
|
- |
|
|
|
0.01 |
|
|
|
|
|
0.02 |
|
|
|
0.95 |
|
|
|
|
|
0.01 |
|
|
|
0.17 |
|
Transportation and processing |
|
|
1.76 |
|
|
|
1.49 |
|
|
|
|
|
5.64 |
|
|
|
4.18 |
|
|
|
|
|
9.90 |
|
|
|
8.30 |
|
Operating |
|
|
0.42 |
|
|
|
0.57 |
|
|
|
|
|
2.12 |
|
|
|
1.42 |
|
|
|
|
|
2.44 |
|
|
|
3.14 |
|
Operating Netback |
|
$ |
2.48 |
|
|
$ |
3.27 |
|
|
|
|
$ |
26.07 |
|
|
$ |
59.07 |
|
|
|
|
$ |
16.45 |
|
|
$ |
24.89 |
|
|
(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$ |
|
|
|
Q2 Report | For the period ended June 30, 2015
|
Six months ended June 30, 2015 versus June 30, 2014
Operating Cash Flow of $584 million decreased $744 million and was impacted by the following significant items:
|
|
|
Lower natural gas prices reflected lower benchmark prices, which decreased revenues $458 million. The average realized natural gas price for production from
Deep Panuke was $9.40 per Mcf compared to $11.31 per Mcf in 2014 and increased the average realized natural gas price $0.73 per Mcf compared to $1.09 per Mcf in 2014. |
|
|
|
Lower liquids prices reflected lower benchmark prices, which decreased revenues $157 million. |
|
|
|
Average natural gas production volumes of 1,004 MMcf/d were lower by 512 MMcf/d, which decreased revenues $539 million. Average oil and NGL production
volumes of 27.0 Mbbls/d were lower by 12.2 Mbbls/d, which decreased revenues $147 million. Changes in production volumes are discussed in the Production Volumes section of this MD&A. |
|
|
|
Realized financial hedging gains were $257 million compared to losses of $124 million in 2014. |
|
|
|
Transportation and processing expense decreased $92 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 production declines at Deep Panuke, partially offset by higher liquids volumes in Montney. |
|
|
|
Operating expense decreased $83 million primarily due to the sale of certain assets included in Wheatland in January 2015, the lower U.S./Canadian dollar
exchange rate, the sale of the Bighorn assets in the third quarter of 2014 and lower long-term compensation costs due to the decrease in the Encana share price. |
Other Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30 |
|
|
|
|
Six months ended June 30 |
|
($ millions, except as indicated) |
|
2015 |
|
|
2014 |
|
|
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
|
Depreciation, depletion & amortization |
|
$ |
68 |
|
|
$ |
165 |
|
|
|
|
$ |
173 |
|
|
$ |
337 |
|
Depletion rate ($/BOE) |
|
|
4.31 |
|
|
|
6.45 |
|
|
|
|
|
4.91 |
|
|
|
6.36 |
|
Depreciation, depletion & amortization (DD&A) decreased in the second quarter and first six
months of 2015 compared to 2014, primarily due to lower production volumes, the lower U.S./Canadian dollar exchange rate and a lower depletion rate. The depletion rate was impacted by the lower U.S./Canadian dollar exchange rate, and the sales of
the Bighorn assets and the Companys investment in PrairieSky in the third quarter of 2014.
|
|
|
|
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
|
Q2 Report | For the period ended June 30,
2015 |
USA Operations
Operating Cash Flow
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30 |
|
|
|
Natural Gas |
|
|
|
|
Oil & NGLs |
|
|
|
|
Total
(1) |
|
($ millions) |
|
2015 |
|
|
2014 |
|
|
|
|
2015 |
|
|
2014 |
|
|
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
|
|
|
|
Revenues, Net of Royalties, excluding Hedging |
|
$ |
146 |
|
|
$ |
463 |
|
|
|
|
$ |
414 |
|
|
$ |
215 |
|
|
|
|
$ |
566 |
|
|
$ |
687 |
|
Realized Financial Hedging Gain (Loss) |
|
|
58 |
|
|
|
(43 |
) |
|
|
|
|
5 |
|
|
|
(6 |
) |
|
|
|
|
63 |
|
|
|
(49 |
) |
Revenues, Net of Royalties |
|
|
204 |
|
|
|
420 |
|
|
|
|
|
419 |
|
|
|
209 |
|
|
|
|
|
629 |
|
|
|
638 |
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and mineral taxes |
|
|
5 |
|
|
|
14 |
|
|
|
|
|
21 |
|
|
|
15 |
|
|
|
|
|
26 |
|
|
|
29 |
|
Transportation and processing |
|
|
142 |
|
|
|
177 |
|
|
|
|
|
2 |
|
|
|
- |
|
|
|
|
|
144 |
|
|
|
177 |
|
Operating |
|
|
46 |
|
|
|
65 |
|
|
|
|
|
104 |
|
|
|
12 |
|
|
|
|
|
151 |
|
|
|
79 |
|
Operating Cash Flow |
|
$ |
11 |
|
|
$ |
164 |
|
|
|
|
$ |
292 |
|
|
$ |
182 |
|
|
|
|
$ |
308 |
|
|
$ |
353 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production Volumes |
|
|
|
|
|
|
|
Three months ended June 30 |
|
|
|
Natural Gas
(MMcf/d) |
|
|
|
|
Oil & NGLs
(Mbbls/d) |
|
|
|
|
Total
(MBOE/d) |
|
|
|
2015 |
|
|
2014 |
|
|
|
|
2015 |
|
|
2014 |
|
|
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
|
|
|
|
Production Volumes After Royalties |
|
|
687 |
|
|
|
1,078 |
|
|
|
|
|
101.0 |
|
|
|
30.8 |
|
|
|
|
|
215.5 |
|
|
|
210.4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Netback (2) |
|
|
|
|
|
|
|
Three months ended June 30 |
|
|
|
Natural
Gas ($/Mcf) |
|
|
|
|
Oil &
NGLs ($/bbl) |
|
|
|
|
Total
($/BOE) |
|
|
|
2015 |
|
|
2014 |
|
|
|
|
2015 |
|
|
2014 |
|
|
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
|
|
|
|
Revenues, Net of Royalties, excluding Hedging |
|
$ |
2.33 |
|
|
$ |
4.72 |
|
|
|
|
$ |
45.21 |
|
|
$ |
77.46 |
|
|
|
|
$ |
28.61 |
|
|
$ |
35.48 |
|
Realized Financial Hedging Gain (Loss) |
|
|
0.93 |
|
|
|
(0.44 |
) |
|
|
|
|
0.52 |
|
|
|
(2.28 |
) |
|
|
|
|
3.22 |
|
|
|
(2.57 |
) |
Revenues, Net of Royalties |
|
|
3.26 |
|
|
|
4.28 |
|
|
|
|
|
45.73 |
|
|
|
75.18 |
|
|
|
|
|
31.83 |
|
|
|
32.91 |
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and mineral taxes |
|
|
0.08 |
|
|
|
0.15 |
|
|
|
|
|
2.26 |
|
|
|
5.19 |
|
|
|
|
|
1.33 |
|
|
|
1.51 |
|
Transportation and processing |
|
|
2.27 |
|
|
|
1.80 |
|
|
|
|
|
0.24 |
|
|
|
- |
|
|
|
|
|
7.34 |
|
|
|
9.23 |
|
Operating |
|
|
0.74 |
|
|
|
0.67 |
|
|
|
|
|
11.28 |
|
|
|
4.29 |
|
|
|
|
|
7.66 |
|
|
|
4.05 |
|
Operating Netback |
|
$ |
0.17 |
|
|
$ |
1.66 |
|
|
|
|
$ |
31.95 |
|
|
$ |
65.70 |
|
|
|
|
$ |
15.50 |
|
|
$ |
18.12 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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$ |
|
|
|
Q2 Report | For the period ended June 30, 2015
|
Three months ended June 30, 2015 versus June 30, 2014
Operating Cash Flow of $308 million decreased $45 million and was impacted by the following significant items:
|
|
|
Lower natural gas prices reflected lower benchmark prices, which decreased revenues $137 million. Lower liquids prices reflected lower benchmark prices,
which decreased revenues $140 million. |
|
|
|
Average natural gas production volumes of 687 MMcf/d were lower by 391 MMcf/d, which decreased revenues $180 million. Average oil and NGL production volumes
of 101.0 Mbbls/d were higher by 70.2 Mbbls/d, which increased revenues $339 million. Changes in production volumes are discussed in the Production Volumes section of this MD&A. |
|
|
|
Realized financial hedging gains were $63 million compared to losses of $49 million in 2014. |
|
|
|
Transportation and processing expense decreased $33 million primarily due to the sales of the Jonah and East Texas properties in the second quarter of 2014
and lower volumes processed mainly in Piceance. |
|
|
|
Operating expense increased $72 million primarily due to the acquisitions of Eagle Ford and the Permian assets in the second and fourth quarters of 2014,
respectively, partially offset by the sales of the Jonah and East Texas properties in the second quarter of 2014 and lower long-term compensation costs due to the decrease in the Encana share price. |
|
|
|
|
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
|
Q2 Report | For the period ended June 30,
2015 |
Operating Cash Flow
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six months ended June 30 |
|
|
|
Natural Gas |
|
|
|
|
Oil & NGLs |
|
|
|
|
Total(1)
|
|
($ millions) |
|
2015 |
|
|
2014 |
|
|
|
|
2015 |
|
|
2014 |
|
|
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
|
|
|
|
Revenues, Net of Royalties, excluding Hedging |
|
$ |
341 |
|
|
$ |
1,059 |
|
|
|
|
$ |
709 |
|
|
$ |
394 |
|
|
|
|
$ |
1,062 |
|
|
$ |
1,465 |
|
Realized Financial Hedging Gain (Loss) |
|
|
112 |
|
|
|
(108 |
) |
|
|
|
|
43 |
|
|
|
(6 |
) |
|
|
|
|
155 |
|
|
|
(114 |
) |
Revenues, Net of Royalties |
|
|
453 |
|
|
|
951 |
|
|
|
|
|
752 |
|
|
|
388 |
|
|
|
|
|
1,217 |
|
|
|
1,351 |
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and mineral taxes |
|
|
9 |
|
|
|
43 |
|
|
|
|
|
36 |
|
|
|
28 |
|
|
|
|
|
45 |
|
|
|
71 |
|
Transportation and processing |
|
|
293 |
|
|
|
340 |
|
|
|
|
|
6 |
|
|
|
- |
|
|
|
|
|
299 |
|
|
|
340 |
|
Operating |
|
|
95 |
|
|
|
133 |
|
|
|
|
|
179 |
|
|
|
20 |
|
|
|
|
|
276 |
|
|
|
153 |
|
Operating Cash Flow |
|
$ |
56 |
|
|
$ |
435 |
|
|
|
|
$ |
531 |
|
|
$ |
340 |
|
|
|
|
$ |
597 |
|
|
$ |
787 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production Volumes |
|
|
|
|
|
|
|
Six months ended June 30 |
|
|
|
Natural Gas
(MMcf/d) |
|
|
|
|
Oil & NGLs
(Mbbls/d) |
|
|
|
|
Total
(MBOE/d) |
|
|
|
2015 |
|
|
2014 |
|
|
|
|
2015 |
|
|
2014 |
|
|
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
|
|
|
|
Production Volumes After Royalties |
|
|
708 |
|
|
|
1,159 |
|
|
|
|
|
97.0 |
|
|
|
28.8 |
|
|
|
|
|
214.9 |
|
|
|
222.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Netback (2) |
|
|
|
|
|
|
|
Six months ended June 30 |
|
|
|
Natural Gas
($/Mcf) |
|
|
|
|
Oil & NGLs ($/bbl) |
|
|
|
|
Total
($/BOE) |
|
|
|
2015 |
|
|
2014 |
|
|
|
|
2015 |
|
|
2014 |
|
|
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
|
|
|
|
Revenues, Net of Royalties, excluding Hedging |
|
$ |
2.66 |
|
|
$ |
5.05 |
|
|
|
|
$ |
40.43 |
|
|
$ |
75.67 |
|
|
|
|
$ |
26.99 |
|
|
$ |
36.18 |
|
Realized Financial Hedging Gain (Loss) |
|
|
0.88 |
|
|
|
(0.51 |
) |
|
|
|
|
2.45 |
|
|
|
(1.21 |
) |
|
|
|
|
3.99 |
|
|
|
(2.83 |
) |
Revenues, Net of Royalties |
|
|
3.54 |
|
|
|
4.54 |
|
|
|
|
|
42.88 |
|
|
|
74.46 |
|
|
|
|
|
30.98 |
|
|
|
33.35 |
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and mineral taxes |
|
|
0.07 |
|
|
|
0.21 |
|
|
|
|
|
2.04 |
|
|
|
5.32 |
|
|
|
|
|
1.15 |
|
|
|
1.76 |
|
Transportation and processing |
|
|
2.29 |
|
|
|
1.62 |
|
|
|
|
|
0.33 |
|
|
|
- |
|
|
|
|
|
7.68 |
|
|
|
8.45 |
|
Operating |
|
|
0.75 |
|
|
|
0.64 |
|
|
|
|
|
10.18 |
|
|
|
3.77 |
|
|
|
|
|
7.05 |
|
|
|
3.81 |
|
Operating Netback |
|
$ |
0.43 |
|
|
$ |
2.07 |
|
|
|
|
$ |
30.33 |
|
|
$ |
65.37 |
|
|
|
|
$ |
15.10 |
|
|
$ |
19.33 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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$ |
|
|
|
Q2 Report | For the period ended June 30, 2015
|
Six months ended June 30, 2015 versus June 30, 2014
Operating Cash Flow of $597 million decreased $190 million and was impacted by the following significant items:
|
|
|
Lower natural gas prices reflected lower benchmark prices, which decreased revenues $277 million. Lower liquids prices reflected lower benchmark prices,
which decreased revenues $259 million. |
|
|
|
Average natural gas production volumes of 708 MMcf/d were lower by 451 MMcf/d, which decreased revenues $441 million. Average oil and NGL production volumes
of 97.0 Mbbls/d were higher by 68.2 Mbbls/d, which increased revenues $574 million. Changes in production volumes are discussed in the Production Volumes section of this MD&A. |
|
|
|
Realized financial hedging gains were $155 million compared to losses of $114 million in 2014. |
|
|
|
Production and mineral taxes decreased $26 million primarily due to the sale of the Jonah properties in the second quarter of 2014 and lower commodity
prices, partially offset by the acquisitions of Eagle Ford and the Permian assets in the second and fourth quarters of 2014, respectively. |
|
|
|
Transportation and processing expense decreased $41 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 $123 million primarily due to the acquisitions of Eagle Ford and the Permian assets in the second and fourth quarters of 2014,
respectively, partially offset by the sales of the Jonah and East Texas properties in the second quarter of 2014 and lower long-term compensation costs due to the decrease in the Encana share price. |
Other Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30 |
|
Six months ended June 30 |
|
($ millions, except as indicated) |
|
2015 |
|
|
2014 |
|
|
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
|
Depreciation, depletion & amortization |
|
$ |
301 |
|
|
$ |
203 |
|
|
|
|
$ |
637 |
|
|
$ |
415 |
|
Depletion rate ($/BOE) |
|
|
15.18 |
|
|
|
10.60 |
|
|
|
|
|
16.07 |
|
|
|
10.33 |
|
Impairments |
|
|
2,081 |
|
|
|
- |
|
|
|
|
|
3,997 |
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DD&A increased in the second quarter and first six 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 impairment recognized in the first
quarter 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 second
quarter and first six months of 2015, the USA Operations recognized before-tax non-cash ceiling test impairments of $2,081 million and $3,997 million, respectively. The impairments primarily resulted from the decline in the 12-month average trailing
commodity prices, which reduced the USA Operations proved reserves volumes and values as calculated under SEC requirements.
The 12-month average
trailing prices used in the ceiling test calculations were based on the benchmark prices below. The benchmark prices were adjusted for basis differentials to determine local reference prices, transportation costs and tariffs, heat content and
quality.
|
|
|
|
|
|
|
|
|
|
|
Natural Gas |
|
|
Oil & NGLs |
|
|
|
Henry Hub ($/MMBtu) |
|
|
WTI
($/bbl) |
|
|
|
|
12-Month Average Trailing Reserves Pricing (1) |
|
|
|
|
|
|
|
|
|
|
|
June 30, 2015 |
|
|
3.38 |
|
|
|
71.68 |
|
December 31, 2014 |
|
|
4.34 |
|
|
|
94.99 |
|
June 30, 2014 |
|
|
4.10 |
|
|
|
100.27 |
|
|
|
|
|
|
|
|
|
|
|
(1) |
All prices were held constant in all future years when estimating reserves. |
|
|
|
|
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
|
Q2 Report | For the period ended June 30,
2015 |
Market Optimization
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30 |
|
|
|
|
Six months ended June 30 |
|
($ millions) |
|
2015 |
|
|
2014 |
|
|
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
|
Revenues |
|
$ |
88 |
|
|
$ |
160 |
|
|
|
|
$ |
227 |
|
|
$ |
404 |
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating |
|
|
8 |
|
|
|
13 |
|
|
|
|
|
24 |
|
|
|
26 |
|
Purchased product |
|
|
79 |
|
|
|
142 |
|
|
|
|
|
200 |
|
|
|
370 |
|
Depreciation, depletion and amortization |
|
|
- |
|
|
|
1 |
|
|
|
|
|
- |
|
|
|
4 |
|
|
|
$ |
1 |
|
|
$ |
4 |
|
|
|
|
$ |
3 |
|
|
$ |
4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 second quarter and first six months of 2015 compared to 2014 primarily due to lower commodity prices,
partially offset by higher volumes required for optimization.
Corporate and Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30 |
|
|
|
|
Six months ended June 30 |
|
($ millions) |
|
2015 |
|
|
2014 |
|
|
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
|
Revenues |
|
$ |
(274 |
) |
|
$ |
36 |
|
|
|
|
$ |
(384 |
) |
|
$ |
(222) |
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transportation and processing |
|
|
(15 |
) |
|
|
(2 |
) |
|
|
|
|
(7 |
) |
|
|
(1) |
|
Operating |
|
|
5 |
|
|
|
8 |
|
|
|
|
|
11 |
|
|
|
18 |
|
Depreciation, depletion and amortization |
|
|
25 |
|
|
|
31 |
|
|
|
|
|
50 |
|
|
|
62 |
|
|
|
$ |
(289 |
) |
|
$ |
(1 |
) |
|
|
|
$ |
(438 |
) |
|
$ |
(301) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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$ |
|
|
|
Q2 Report | For the period ended June 30,
2015 |
Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30 |
|
|
|
|
Six months ended June 30 |
|
($ millions) |
|
2015 |
|
|
2014 |
|
|
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
|
Accretion of asset retirement obligation |
|
$ |
11 |
|
|
$ |
13 |
|
|
|
|
$ |
23 |
|
|
$ |
26 |
|
Administrative |
|
|
84 |
|
|
|
98 |
|
|
|
|
|
156 |
|
|
|
200 |
|
Interest |
|
|
278 |
|
|
|
122 |
|
|
|
|
|
403 |
|
|
|
269 |
|
Foreign exchange (gain) loss, net |
|
|
(86 |
) |
|
|
(172 |
) |
|
|
|
|
570 |
|
|
|
52 |
|
(Gain) loss on divestitures |
|
|
(2 |
) |
|
|
(204 |
) |
|
|
|
|
(16 |
) |
|
|
(203 |
) |
Other |
|
|
4 |
|
|
|
8 |
|
|
|
|
|
5 |
|
|
|
8 |
|
|
|
$ |
289 |
|
|
$ |
(135 |
) |
|
|
|
$ |
1,141 |
|
|
$ |
352 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Administrative expense in the second quarter and first six 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 $15 million and $30 million for the second quarter and first six months of 2015, respectively. Restructuring costs attributable to
work force reductions associated with the 2013 restructuring were $1 million in the second quarter and first six months of 2015 compared with $7 million and $22 million in the second quarter and first six months of 2014, respectively.
Interest expense in the second quarter and first six months of 2015 increased from 2014 primarily due to a one-time interest payment of approximately
$165 million resulting from the early redemption of Encanas $700 million 5.90 percent notes due December 1, 2017 and C$750 million 5.80 percent medium-term notes due January 18, 2018.
Foreign exchange gains and losses result from the impact of the fluctuations in the Canadian to U.S. dollar exchange rate. In the second quarter of 2015
compared to 2014, the Company recorded higher foreign exchange losses on settlements and lower foreign exchange gains on the translation of U.S. dollar long-term debt issued from Canada, partially offset by foreign exchange gains on the translation
of intercompany notes. In the first six months of 2015 compared to 2014, Encana recorded higher foreign exchange losses on the translation of U.S. dollar long-term debt issued from Canada and on settlements.
Gain on divestitures in the first six months of 2015 primarily includes a gain on the sale of the Encana Place office building in Calgary. Gain on
divestitures in the second quarter and first six months of 2014 primarily includes the before tax impact of the sale of the Jonah properties, as discussed in the Net Capital Investment section of this MD&A.
|
|
|
|
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
|
Q2 Report | For the period ended June 30,
2015 |
Income Tax
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30 |
|
|
|
|
Six months ended June 30 |
|
($ millions) |
|
|
2015 |
|
|
|
2014 |
|
|
|
|
|
2015 |
|
|
|
2014 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current Income Tax (Recovery) |
|
$ |
(35) |
|
|
$ |
(19) |
|
|
|
|
$ |
(19) |
|
|
$ |
(3) |
|
Deferred Income Tax (Recovery) |
|
|
(903) |
|
|
|
308 |
|
|
|
|
|
(1,866) |
|
|
|
320 |
|
Income Tax Expense (Recovery) |
|
$ |
(938) |
|
|
$ |
289 |
|
|
|
|
$ |
(1,885) |
|
|
$ |
317 |
|
Total income tax recovery in the first six 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 Companys effective tax rate for the first six months of 2015 is lower than 2014 primarily as a result of changes in expected annual earnings and income tax expense recognized on the sale of a noncontrolling interest in PrairieSky in the
second quarter of 2014. 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.
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.
|
Liquidity and Capital Resources |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30 |
|
|
|
|
Six months ended June 30 |
|
($ millions) |
|
|
2015 |
|
|
|
2014 |
|
|
|
|
|
2015 |
|
|
|
2014 |
|
|
|
|
|
|
|
|
|
Net Cash From (Used In) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities |
|
$ |
298 |
|
|
$ |
767 |
|
|
|
|
$ |
780 |
|
|
$ |
1,710 |
|
Investing activities |
|
|
(681) |
|
|
|
(1,489) |
|
|
|
|
|
(413) |
|
|
|
(1,935) |
|
Financing activities |
|
|
(1,170) |
|
|
|
1,171 |
|
|
|
|
|
(202) |
|
|
|
326 |
|
Foreign exchange gain (loss) on cash and cash equivalents held in foreign
currency |
|
|
19 |
|
|
|
47 |
|
|
|
|
|
(7) |
|
|
|
(9) |
|
Increase (Decrease) in Cash and Cash Equivalents |
|
$ |
(1,534) |
|
|
$ |
496 |
|
|
|
|
$ |
158 |
|
|
$ |
92 |
|
Cash and Cash Equivalents, End of Period |
|
$ |
496 |
|
|
$ |
2,658 |
|
|
|
|
$ |
496 |
|
|
$ |
2,658 |
|
Operating Activities
Net cash from operating activities in the
second quarter of 2015 of $298 million decreased $469 million from 2014. These changes are primarily a result of the Cash Flow variances discussed in the Financial Results section of this MD&A. In the second quarter of 2015, the net change in
non-cash working capital was a surplus of $110 million compared to $119 million in 2014.
Net cash from operating activities in the first six months
of 2015 of $780 million decreased $930 million from 2014. These changes are primarily a result of the Cash Flow variances discussed in the Financial Results section of this MD&A. In the first six months of 2015, the net change in non-cash
working capital was a surplus of $104 million compared to a deficit of $23 million in 2014.
|
|
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
|
|
|
Q2 Report | For the period ended June 30, 2015
|
The Company had a working capital surplus of $290 million at June 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, a decrease in risk management assets and a decrease in income tax receivable, partially offset by a
decrease in accounts payable and accrued liabilities, an increase in cash and cash equivalents, an increase in deferred income tax assets and a decrease in deferred income tax liabilities. At June 30, 2015, working capital included cash and
cash equivalents of $496 million compared to $338 million at December 31, 2014. Encana expects that it will continue to meet the payment terms of its suppliers.
Investing Activities
Net cash used in investing activities in the first six months of 2015 was $413 million compared to $1,935 million in 2014. The decrease was primarily due
to the acquisition of Eagle Ford in 2014, partially offset by lower proceeds from divestitures. Further information on acquisitions and divestitures can be found in the Net Capital Investment section of this MD&A.
Financing Activities
Net cash used in financing activities in the first six months of 2015 was $202 million compared to net cash from financing activities of $326 million in
2014. The change was primarily due to the sale of a noncontrolling interest in PrairieSky in the second quarter of 2014, partially offset by proceeds from the issuance of common shares pursuant to the Share Offering in the first quarter of 2015.
Credit Facilities
The following table
outlines the Companys committed revolving bank credit facilities at June 30, 2015:
|
|
|
|
|
|
|
|
|
|
|
|
|
($ billions) |
|
Capacity |
|
|
Unused |
|
|
Maturity Date |
|
|
|
|
|
Committed Revolving Bank Credit Facilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Encana Credit Facility (1), (2) |
|
|
2.8 |
|
|
|
1.4 |
|
|
|
June 2018 |
|
|
|
|
|
U.S. Subsidiary Credit Facility |
|
|
1.0 |
|
|
|
1.0 |
|
|
|
June 2018 |
|
(1) |
The Encana Credit Facility is Canadian dollar denominated with a capacity of C$3.5 billion. |
(2) |
At June 30, 2015, $1.4 billion was fully supporting the U.S. Commercial Paper Program, as discussed in the Long-Term Debt section below. |
On July 16, 2015, the Company changed its Encana Credit Facility from Canadian dollars to U.S. dollars and amended the capacity to $3.0 billion.
The Company also amended the capacity of its U.S. subsidiary Credit Facility to $1.5 billion. The maturity date for both Credit Facilities was extended to July 2020 and $3.1 billion remained unused at July 16, 2015.
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 28 percent at June 30, 2015 and 30 percent at December 31, 2014.
Long-Term Debt
Encanas long-term debt, excluding the current portion, totaled $6,112 million at June 30, 2015 and $7,340 million at
December 31, 2014. There was no current portion of long-term debt outstanding at June 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$750 million 5.80 percent
|
|
|
|
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
|
Q2 Report | For the period ended June 30,
2015 |
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 redemption.
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 June 30, 2015, Encana had an outstanding balance of $1,397 million
which reflected U.S. CP issuances that had an average term of 45 days and a weighted average interest rate of 0.66 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.
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 June 30, 2015, $4.9 billion, or the
equivalent in foreign currencies, remained accessible under the shelf prospectus, the availability of which is dependent upon market conditions. The shelf prospectus expires in July 2016.
Outstanding Share Data
|
|
|
|
|
|
|
|
|
|
|
|
|
(millions) |
|
December 31, 2014 |
|
|
June 30, 2015 |
|
|
July 17, 2015 |
|
|
|
|
|
Common Shares Outstanding |
|
|
741.2 |
|
|
|
842.5 |
|
|
|
842.5 |
|
|
|
|
|
Stock Options with TSARs attached (1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding |
|
|
21.3 |
|
|
|
20.3 |
|
|
|
20.2 |
|
|
|
|
|
Exercisable |
|
|
10.0 |
|
|
|
11.2 |
|
|
|
11.1 |
|
(1) |
A Tandem Stock Appreciation Right (TSAR) gives the option holder the right to receive a cash payment equal to the excess of the market price of Encanas common shares at the time of exercise over the
original grant price. |
During the first quarter of 2015, Encana issued common shares pursuant to the Share Offering as discussed
above.
During the first six months of 2015, Encana issued 2,872,237 common shares under the Companys dividend reinvestment plan
(DRIP) compared with 113,775 common shares in 2014. The number of common shares issued under the DRIP increased in the first six months of 2015 primarily as a result of Encanas February 25, 2015 announcement that, effective
with the dividend payable on March 31, 2015, any future dividends in conjunction with the DRIP will be issued from its treasury with a two percent discount to the average market price of the common shares unless otherwise announced by the
Company via news release.
|
|
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
|
|
|
Q2 Report | For the period ended June 30, 2015
|
Dividends
Encana pays quarterly dividends to shareholders at the discretion of the Board.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30 |
|
|
|
|
Six months ended June 30 |
|
($ millions, except as indicated) |
|
2015 |
|
|
2014 |
|
|
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
|
Dividend Payments |
|
$ |
55 |
|
|
$ |
52 |
|
|
|
|
$ |
107 |
|
|
$ |
104 |
|
|
|
|
|
|
|
Dividend Payments ($/share) |
|
|
0.07 |
|
|
|
0.07 |
|
|
|
|
|
0.14 |
|
|
|
0.14 |
|
The dividends paid in the second quarter and first six months of 2015 included $18 million and $32 million, respectively, in common
shares issued in lieu of cash dividends under the DRIP compared to $2 million and $3 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 July 23, 2015, the Board declared a dividend of $0.07 per share payable on September 30, 2015 to common shareholders of record as of
September 15, 2015.
Capital Structure
The Companys capital structure consists of total shareholders equity plus long-term debt, including the current portion. The Companys objectives when
managing its capital structure are to maintain financial flexibility to preserve Encanas access to capital markets and its ability to meet financial obligations and finance internally generated growth, as well as potential acquisitions. Encana
has a long-standing practice of maintaining capital discipline and managing and adjusting its capital structure according to market conditions to maintain flexibility while achieving the Companys objectives.
To manage the capital structure, the Company may adjust capital spending, adjust dividends paid to shareholders, issue new shares, issue new debt or repay existing
debt. In managing its capital structure, the Company monitors the following non-GAAP financial metrics as indicators of its overall financial strength, which are defined in the Non-GAAP Measures section of this MD&A.
|
|
|
|
|
|
|
|
|
|
|
June 30, 2015 |
|
|
December 31, 2014 |
|
|
|
|
Debt to Debt Adjusted Cash Flow |
|
|
2.5x |
|
|
|
2.1x |
|
|
|
|
Debt to Adjusted Capitalization |
|
|
28% |
|
|
|
30% |
|
|
|
|
|
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
|
Q2 Report | For the period ended June 30,
2015 |
|
Commitments and Contingencies |
Commitments
The following table outlines the Companys commitments at June 30, 2015:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected Future Payments |
|
($ millions, undiscounted) |
|
2015 |
|
|
2016 |
|
|
2017 |
|
|
2018 |
|
|
2019 |
|
|
Thereafter |
|
|
Total |
|
|
|
|
|
|
|
|
|
Transportation and Processing |
|
$ |
427 |
|
|
$ |
817 |
|
|
$ |
800 |
|
|
$ |
816 |
|
|
$ |
697 |
|
|
$ |
3,253 |
|
|
$ |
6,810 |
|
|
|
|
|
|
|
|
|
Drilling and Field Services |
|
|
125 |
|
|
|
136 |
|
|
|
102 |
|
|
|
51 |
|
|
|
15 |
|
|
|
16 |
|
|
|
445 |
|
|
|
|
|
|
|
|
|
Operating Leases |
|
|
18 |
|
|
|
30 |
|
|
|
25 |
|
|
|
24 |
|
|
|
11 |
|
|
|
24 |
|
|
|
132 |
|
Commitments |
|
$ |
570 |
|
|
$ |
983 |
|
|
$ |
927 |
|
|
$ |
891 |
|
|
$ |
723 |
|
|
$ |
3,293 |
|
|
$ |
7,387 |
|
In addition to the Commitments disclosed above, Encana 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.
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.
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. Further information can be found in Note 21 to the Interim Condensed Consolidated Financial Statements regarding the Companys risk management program.
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.
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$ |
|
|
|
Q2 Report | For the period ended June 30, 2015
|
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, which allows the Company to respond well 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 issues.
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 set a floor and cap on prices. 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 June 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. This credit exposure is mitigated 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$ |
|
Q2 Report | For the period ended June 30,
2015 |
facilities and 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 prices mentioned above, continued market demand for its products and other risk 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; volatility in natural gas and liquids prices; 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 announced that it had appointed a chairman who will form a panel to undertake a review of the
provinces oil and gas royalty structure. The panel is expected to consult with industry, the public and stakeholders and report back to the Alberta Government by the end of 2015. Over the coming months, Encana will monitor the work of the
panel and engage 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$ |
|
|
|
Q2 Report | For the period ended June 30, 2015
|
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 which have not yet been announced. The EPA plans to propose this new rule and guidance in late summer 2015 with a final rule and guidance expected 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$30 per tonne by 2017 for those facilities that are unable to meet the specified reduction targets. Encana does
not own or operate any facilities which exceed the 100,000 tonne threshold and, as a result, is not currently subject to the Regulation.
In
addition to the renewal of the Regulation, the Alberta Government also announced the formation of an advisory panel that will comprehensively review Albertas climate change policy, consult stakeholders and provide advice on a permanent set of
measures. The panel is expected to conduct stakeholder consultations during the summer of 2015 and will report back to the Alberta Government in the fall. Over the coming months, Encana will monitor the work of the advisory panel and engage in the
consultations as appropriate.
A comprehensive discussion of Encanas risk management is provided in the Companys annual MD&A for the
year ended December 31, 2014.
|
|
|
|
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
|
Q2 Report | For the period ended June 30,
2015 |
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. No material weaknesses or significant deficiencies were noted during the integration and there have been no other changes to the Companys internal
control over financial reporting during the three months ended June 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.
|
|
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
|
|
|
Q2 Report | For the period ended June 30, 2015
|
|
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.
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. The amendments will be applied retrospectively. As at June 30, 2015, $34 million of debt issuance
costs were presented in Other Assets on the Companys interim Condensed Consolidated Balance Sheet ($39 million as at December 31, 2014). |
As of January 1, 2017, Encana will be required to adopt ASU 2014-09, Revenue from Contracts with Customers under Topic 606, which was the
result of a joint project by the FASB and International Accounting Standards Board. The new standard replaces Topic 605, Revenue Recognition, and other industry-specific guidance in the Accounting Standards Codification. The new standard is
based on the principle that revenue is recognized on the transfer of promised goods or services to customers in an amount that reflects the consideration the Company expects to be entitled to in exchange for those goods or services. The standard can
be applied using either the full retrospective approach or a modified retrospective approach at the date of adoption. Encana is currently assessing the potential impact of the standard on the Companys Consolidated Financial Statements.
|
|
|
|
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
|
Q2 Report | For the period ended June 30,
2015 |
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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six months
ended June 30 |
|
|
|
|
2015 |
|
|
|
|
2014 |
|
|
|
|
2013 |
|
($ millions) |
|
|
2015 |
|
|
|
2014 |
|
|
|
|
|
Q2 |
|
|
|
Q1 |
|
|
|
|
|
Q4 |
|
|
|
Q3 |
|
|
|
Q2 |
|
|
|
Q1 |
|
|
|
|
|
Q4 |
|
|
|
Q3 |
|
Cash From (Used in) Operating Activities |
|
$ |
780 |
|
|
$ |
1,710 |
|
|
|
|
$ |
298 |
|
|
$ |
482 |
|
|
|
|
$ |
261 |
|
|
$ |
696 |
|
|
$ |
767 |
|
|
$ |
943 |
|
|
|
|
$ |
462 |
|
|
$ |
935 |
|
(Add back) deduct: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net change in other assets and liabilities |
|
|
- |
|
|
|
(17 |
) |
|
|
|
|
7 |
|
|
|
(7 |
) |
|
|
|
|
(15 |
) |
|
|
(11 |
) |
|
|
(8 |
) |
|
|
(9 |
) |
|
|
|
|
(21 |
) |
|
|
(15 |
) |
Net change in non-cash working capital |
|
|
104 |
|
|
|
(23 |
) |
|
|
|
|
110 |
|
|
|
(6 |
) |
|
|
|
|
(141 |
) |
|
|
155 |
|
|
|
119 |
|
|
|
(142 |
) |
|
|
|
|
(183 |
) |
|
|
300 |
|
Cash tax on sale of assets |
|
|
- |
|
|
|
- |
|
|
|
|
|
- |
|
|
|
- |
|
|
|
|
|
40 |
|
|
|
(255 |
) |
|
|
- |
|
|
|
- |
|
|
|
|
|
(11 |
) |
|
|
(10 |
) |
Cash Flow |
|
$ |
676 |
|
|
$ |
1,750 |
|
|
|
|
$ |
181 |
|
|
$ |
495 |
|
|
|
|
$ |
377 |
|
|
$ |
807 |
|
|
$ |
656 |
|
|
$ |
1,094 |
|
|
|
|
$ |
677 |
|
|
$ |
660 |
|
Deduct: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital investment |
|
|
1,479 |
|
|
|
1,071 |
|
|
|
|
|
743 |
|
|
|
736 |
|
|
|
|
|
857 |
|
|
|
598 |
|
|
|
560 |
|
|
|
511 |
|
|
|
|
|
717 |
|
|
|
641 |
|
Free Cash Flow |
|
$ |
(803 |
) |
|
$ |
679 |
|
|
|
|
$ |
(562 |
) |
|
$ |
(241 |
) |
|
|
|
$ |
(480) |
|
|
$ |
209 |
|
|
$ |
96 |
|
|
$ |
583 |
|
|
|
|
$ |
(40) |
|
|
$ |
19 |
|
|
|
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
|
|
|
Q2 Report | For the period ended June 30, 2015
|
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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six months ended June 30 |
|
|
|
|
2015 |
|
|
|
|
2014 |
|
|
|
|
2013 |
|
($ millions) |
|
|
2015 |
|
|
|
2014 |
|
|
|
|
|
Q2 |
|
|
|
Q1 |
|
|
|
|
|
Q4 |
|
|
|
Q3 |
|
|
|
Q2 |
|
|
|
Q1 |
|
|
|
|
|
Q4 |
|
|
|
Q3 |
|
Net Earnings (Loss) Attributable to Common Shareholders |
|
$ |
(3,317 |
) |
|
$ |
387 |
|
|
|
|
$ |
(1,610 |
) |
|
$ |
(1,707 |
) |
|
|
|
$ |
198 |
|
|
$ |
2,807 |
|
|
$ |
271 |
|
|
$ |
116 |
|
|
|
|
$ |
(251 |
) |
|
$ |
188 |
|
After-tax (addition) / deduction: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized hedging gain (loss) |
|
|
(285 |
) |
|
|
(195 |
) |
|
|
|
|
(187 |
) |
|
|
(98 |
) |
|
|
|
|
341 |
|
|
|
160 |
|
|
|
8 |
|
|
|
(203 |
) |
|
|
|
|
(209 |
) |
|
|
(89 |
) |
Impairments |
|
|
(2,550 |
) |
|
|
- |
|
|
|
|
|
(1,328 |
) |
|
|
(1,222 |
) |
|
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
|
|
- |
|
|
|
(16 |
) |
Restructuring charges (1) |
|
|
(20 |
) |
|
|
(15 |
) |
|
|
|
|
(10 |
) |
|
|
(10 |
) |
|
|
|
|
(4 |
) |
|
|
(5 |
) |
|
|
(5 |
) |
|
|
(10 |
) |
|
|
|
|
(64 |
) |
|
|
- |
|
Non-operating foreign exchange gain (loss) |
|
|
(394 |
) |
|
|
(38 |
) |
|
|
|
|
114 |
|
|
|
(508 |
) |
|
|
|
|
(151 |
) |
|
|
(218 |
) |
|
|
156 |
|
|
|
(194 |
) |
|
|
|
|
(124 |
) |
|
|
105 |
|
Gain (loss) on divestitures |
|
|
11 |
|
|
|
135 |
|
|
|
|
|
1 |
|
|
|
10 |
|
|
|
|
|
(11 |
) |
|
|
2,399 |
|
|
|
135 |
|
|
|
- |
|
|
|
|
|
- |
|
|
|
- |
|
Income tax adjustments |
|
|
69 |
|
|
|
(186 |
) |
|
|
|
|
(33 |
) |
|
|
102 |
|
|
|
|
|
(12 |
) |
|
|
190 |
|
|
|
(194 |
) |
|
|
8 |
|
|
|
|
|
(80 |
) |
|
|
38 |
|
Operating Earnings (Loss) (1) |
|
$ |
(148 |
) |
|
$ |
686 |
|
|
|
|
$ |
(167 |
) |
|
$ |
19 |
|
|
|
|
$ |
35 |
|
|
$ |
281 |
|
|
$ |
171 |
|
|
$ |
515 |
|
|
|
|
$ |
226 |
|
|
$ |
150 |
|
(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$ |
|
Q2 Report | For the period ended June 30,
2015 |
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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six months ended June 30 |
|
|
|
|
2015 |
|
|
|
|
2014 |
|
|
|
|
2013 |
|
($ millions) |
|
|
2015 |
|
|
|
2014 |
|
|
|
|
|
Q2 |
|
|
|
Q1 |
|
|
|
|
|
Q4 |
|
|
|
Q3 |
|
|
|
Q2 |
|
|
|
Q1 |
|
|
|
|
|
Q4 |
|
|
|
Q3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Upstream Operating Cash Flow |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
$ |
584 |
|
|
$ |
1,328 |
|
|
|
|
$ |
171 |
|
|
$ |
413 |
|
|
|
|
$ |
341 |
|
|
$ |
477 |
|
|
$ |
447 |
|
|
$ |
881 |
|
|
|
|
$ |
526 |
|
|
$ |
406 |
|
USA Operations |
|
|
597 |
|
|
|
787 |
|
|
|
|
|
308 |
|
|
|
289 |
|
|
|
|
|
480 |
|
|
|
505 |
|
|
|
353 |
|
|
|
434 |
|
|
|
|
|
375 |
|
|
|
388 |
|
|
|
$ |
1,181 |
|
|
$ |
2,115 |
|
|
|
|
$ |
479 |
|
|
$ |
702 |
|
|
|
|
$ |
821 |
|
|
$ |
982 |
|
|
$ |
800 |
|
|
$ |
1,315 |
|
|
|
|
$ |
901 |
|
|
$ |
794 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Add back) deduct: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized Hedging Gain (Loss) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
$ |
257 |
|
|
$ |
(124 |
) |
|
|
|
$ |
101 |
|
|
$ |
156 |
|
|
|
|
$ |
49 |
|
|
$ |
19 |
|
|
$ |
(49 |
) |
|
$ |
(75 |
) |
|
|
|
$ |
90 |
|
|
$ |
95 |
|
USA Operations |
|
|
155 |
|
|
|
(114 |
) |
|
|
|
|
63 |
|
|
|
92 |
|
|
|
|
|
78 |
|
|
|
11 |
|
|
|
(49 |
) |
|
|
(65 |
) |
|
|
|
|
83 |
|
|
|
77 |
|
|
|
$ |
412 |
|
|
$ |
(238 |
) |
|
|
|
$ |
164 |
|
|
$ |
248 |
|
|
|
|
$ |
127 |
|
|
$ |
30 |
|
|
$ |
(98 |
) |
|
$ |
(140 |
) |
|
|
|
$ |
173 |
|
|
$ |
172 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Upstream Operating Cash Flow, excluding Hedging |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
$ |
327 |
|
|
$ |
1,452 |
|
|
|
|
$ |
70 |
|
|
$ |
257 |
|
|
|
|
$ |
292 |
|
|
$ |
458 |
|
|
$ |
496 |
|
|
$ |
956 |
|
|
|
|
$ |
436 |
|
|
$ |
311 |
|
USA Operations |
|
|
442 |
|
|
|
901 |
|
|
|
|
|
245 |
|
|
|
197 |
|
|
|
|
|
402 |
|
|
|
494 |
|
|
|
402 |
|
|
|
499 |
|
|
|
|
|
292 |
|
|
|
311 |
|
|
|
$ |
769 |
|
|
$ |
2,353 |
|
|
|
|
$ |
315 |
|
|
$ |
454 |
|
|
|
|
$ |
694 |
|
|
$ |
952 |
|
|
$ |
898 |
|
|
$ |
1,455 |
|
|
|
|
$ |
728 |
|
|
$ |
622 |
|
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$ |
|
|
|
Q2 Report | For the period ended June 30, 2015
|
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) |
|
June 30, 2015 |
|
|
December 31, 2014 |
|
|
|
|
Debt |
|
$ |
6,112 |
|
|
$ |
7,340 |
|
|
|
|
Cash Flow |
|
|
1,860 |
|
|
|
2,934 |
|
Interest Expense, after tax |
|
|
583 |
|
|
|
486 |
|
Debt Adjusted Cash Flow |
|
$ |
2,443 |
|
|
$ |
3,420 |
|
Debt to Debt Adjusted Cash Flow |
|
|
2.5x |
|
|
|
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) |
|
June 30, 2015 |
|
|
December 31, 2014 |
|
|
|
|
Debt |
|
$ |
6,112 |
|
|
$ |
7,340 |
|
Total Shareholders
Equity |
|
|
7,817 |
|
|
|
9,685 |
|
Equity Adjustment for Impairments at December 31, 2011 |
|
|
7,746 |
|
|
|
7,746 |
|
Adjusted Capitalization |
|
$ |
21,675 |
|
|
$ |
24,771 |
|
Debt to Adjusted Capitalization |
|
|
28% |
|
|
|
30% |
|
|
|
|
|
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
|
Q2 Report | For the period ended June 30,
2015 |
Forward-Looking Statements
Certain statements contained in this
document constitute forward-looking statements or information (collectively, forward-looking statements) within the meaning of the safe harbour provisions of applicable securities legislation. Forward-looking statements are
typically identified by words such as anticipate, believe, expect, plan, intend, forecast, target, project, objective, strategy,
strives, agreed to or similar words suggesting future outcomes or statements regarding an outlook. In this document, forward-looking statements include, but are not limited to:
|
|
|
anticipated cash and cash equivalents |
|
|
|
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 |
|
|
|
the Companys expectation to fund its 2015 commitments and obligations from Cash Flow and cash and cash equivalents |
|
|
|
anticipated revenues and operating expenses |
|
|
|
anticipated future cost and operating efficiencies |
|
|
|
the continued evolution of the Companys resource play hub model to drive greater productivity and cost efficiencies |
|
|
|
statements with respect to future ceiling test impairments
|
|
|
|
estimates of reserves and resources |
|
|
|
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 |
|
|
|
managing risk, including the possible impact of changes to the royalty structure |
|
|
|
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 |
|
|
|
flexibility of capital spending plans |
|
|
|
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 130,000 bbls/d to 150,000 bbls/d of liquids |
|
|
|
commodity prices for natural gas and liquids based on NYMEX of $3.00 per MMBtu and WTI of $50 per bbl through the remainder of 2015 |
|
|
|
U.S./Canadian dollar exchange rate of 0.80 |
|
|
|
a weighted average number of outstanding shares of approximately 821 million
|
|
|
|
effectiveness of the Companys resource play hub model to drive productivity and efficiencies |
|
|
|
results from innovations |
|
|
|
availability of attractive hedge contracts |
|
|
|
expectations and projections made in light of, and generally consistent with, Encanas historical experience and its perception of historical trends, including with respect to the pace of technological development,
the benefits achieved and general industry expectations |
|
|
|
|
|
MD&A
Prepared using U.S. GAAP in US$ |
|
|
|
Q2 Report | For the period ended June 30, 2015
|
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; 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 July 24, 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$ |
|
Q2 Report | For the period ended June 30,
2015 |
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
In this document,
certain natural gas volumes have been converted to BOE on the basis of six Mcf to one bbl. BOE may be misleading, particularly if used in isolation. A conversion ratio of 6:1 is based on an energy equivalency conversion method primarily applicable
at the burner tip and does not represent value equivalency at the wellhead.
Given that the value ratio based on the current price of natural gas as
compared to oil is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.
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$ |
|
|
|
Q2 Report | For the period ended June 30, 2015
|
Condensed Consolidated Statement of Earnings
(unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
June 30, |
|
|
Six Months Ended
June 30, |
|
($ millions, except per share amounts) |
|
|
|
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
|
Revenues, Net of
Royalties |
|
|
(Note 3 |
) |
|
$ |
830 |
|
|
$ |
1,588 |
|
|
$ |
2,079 |
|
|
$ |
3,480 |
|
|
|
|
|
|
|
Expenses |
|
|
(Note 3 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and mineral taxes |
|
|
|
|
|
|
26 |
|
|
|
33 |
|
|
|
45 |
|
|
|
80 |
|
Transportation and processing |
|
|
|
|
|
|
300 |
|
|
|
400 |
|
|
|
640 |
|
|
|
779 |
|
Operating |
|
|
|
|
|
|
209 |
|
|
|
178 |
|
|
|
398 |
|
|
|
367 |
|
Purchased product |
|
|
|
|
|
|
79 |
|
|
|
142 |
|
|
|
200 |
|
|
|
370 |
|
Depreciation, depletion and
amortization |
|
|
|
|
|
|
394 |
|
|
|
400 |
|
|
|
860 |
|
|
|
818 |
|
Impairments |
|
|
(Note 9 |
) |
|
|
2,081 |
|
|
|
- |
|
|
|
3,997 |
|
|
|
- |
|
Accretion of asset retirement
obligation |
|
|
(Note 12 |
) |
|
|
11 |
|
|
|
13 |
|
|
|
23 |
|
|
|
26 |
|
Administrative |
|
|
(Note 17 |
) |
|
|
84 |
|
|
|
98 |
|
|
|
156 |
|
|
|
200 |
|
Interest |
|
|
(Note 6 |
) |
|
|
278 |
|
|
|
122 |
|
|
|
403 |
|
|
|
269 |
|
Foreign exchange (gain) loss,
net |
|
|
(Note 7 |
) |
|
|
(86 |
) |
|
|
(172 |
) |
|
|
570 |
|
|
|
52 |
|
(Gain) loss on divestitures |
|
|
(Note 5 |
) |
|
|
(2 |
) |
|
|
(204 |
) |
|
|
(16 |
) |
|
|
(203 |
) |
Other |
|
|
|
|
|
|
4 |
|
|
|
8 |
|
|
|
5 |
|
|
|
8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,378 |
|
|
|
1,018 |
|
|
|
7,281 |
|
|
|
2,766 |
|
Net Earnings (Loss) Before Income
Tax |
|
|
|
|
|
|
(2,548 |
) |
|
|
570 |
|
|
|
(5,202 |
) |
|
|
714 |
|
Income tax expense (recovery) |
|
|
(Note 8 |
) |
|
|
(938 |
) |
|
|
289 |
|
|
|
(1,885 |
) |
|
|
317 |
|
Net Earnings (Loss) |
|
|
|
|
|
|
(1,610 |
) |
|
|
281 |
|
|
|
(3,317 |
) |
|
|
397 |
|
Net earnings attributable to noncontrolling interest |
|
|
(Note 15 |
) |
|
|
- |
|
|
|
(10 |
) |
|
|
- |
|
|
|
(10 |
) |
|
|
|
|
|
Net Earnings (Loss) Attributable to Common Shareholders |
|
|
$ |
(1,610 |
) |
|
$ |
271 |
|
|
$ |
(3,317 |
) |
|
$ |
387 |
|
|
|
|
|
|
|
Net Earnings (Loss) per Common
Share |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic & Diluted |
|
|
(Note 13 |
) |
|
$ |
(1.91 |
) |
|
$ |
0.37 |
|
|
$ |
(4.15 |
) |
|
$ |
0.52 |
|
Condensed Consolidated Statement of Comprehensive Income (unaudited) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
June 30, |
|
|
Six Months Ended
June 30, |
|
($ millions) |
|
|
|
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
|
Net Earnings (Loss) |
|
|
|
|
|
$ |
(1,610 |
) |
|
$ |
281 |
|
|
$ |
(3,317 |
) |
|
$ |
397 |
|
Other Comprehensive Income (Loss),
Net of Tax |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign currency translation
adjustment |
|
|
(Note 14 |
) |
|
|
(53 |
) |
|
|
(2 |
) |
|
|
425 |
|
|
|
22 |
|
Pension and other post-employment benefit plans |
|
|
(Notes 14, 19 |
) |
|
|
- |
|
|
|
- |
|
|
|
1 |
|
|
|
- |
|
Other Comprehensive Income (Loss) |
|
|
|
|
|
|
(53 |
) |
|
|
(2 |
) |
|
|
426 |
|
|
|
22 |
|
Comprehensive Income
(Loss) |
|
|
|
|
|
|
(1,663 |
) |
|
|
279 |
|
|
|
(2,891 |
) |
|
|
419 |
|
Comprehensive Income Attributable to Noncontrolling Interest |
|
|
(Note 15 |
) |
|
|
- |
|
|
|
(10 |
) |
|
|
- |
|
|
|
(10 |
) |
|
|
|
|
|
Comprehensive Income (Loss) Attributable to Common Shareholders |
|
|
$ |
(1,663 |
) |
|
$ |
269 |
|
|
$ |
(2,891 |
) |
|
$ |
409 |
|
See accompanying Notes to Condensed Consolidated Financial Statements
|
|
|
|
|
|
|
Condensed Consolidated Financial Statements
Prepared in accordance with U.S. GAAP in US$ |
|
Q2 Report | For the period ended June 30,
2015 |
Condensed Consolidated Balance Sheet (unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
($ millions) |
|
|
|
|
As at
June 30, 2015 |
|
|
As at
December 31, 2014 |
|
|
|
|
|
Assets |
|
|
|
|
|
|
|
|
|
|
|
|
Current Assets |
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
|
|
|
|
$ |
496 |
|
|
$ |
338 |
|
Accounts receivable and accrued revenues |
|
|
|
|
|
|
751 |
|
|
|
1,307 |
|
Risk management |
|
|
(Note 21 |
) |
|
|
330 |
|
|
|
707 |
|
Income tax receivable |
|
|
|
|
|
|
408 |
|
|
|
509 |
|
Deferred income taxes |
|
|
|
|
|
|
112 |
|
|
|
- |
|
|
|
|
|
|
|
|
2,097 |
|
|
|
2,861 |
|
Property, Plant and Equipment, at cost: |
|
|
(Note 9 |
) |
|
|
|
|
|
|
|
|
Natural gas and oil properties, based on full cost accounting |
|
|
|
|
|
|
|
|
|
|
|
|
Proved properties |
|
|
|
|
|
|
42,084 |
|
|
|
42,615 |
|
Unproved properties |
|
|
|
|
|
|
5,855 |
|
|
|
6,133 |
|
Other |
|
|
|
|
|
|
2,478 |
|
|
|
2,711 |
|
Property, plant and equipment |
|
|
|
|
|
|
50,417 |
|
|
|
51,459 |
|
Less: Accumulated depreciation, depletion and amortization |
|
|
|
|
|
|
(37,088 |
) |
|
|
(33,444 |
) |
Property, plant and equipment, net |
|
|
(Note 3 |
) |
|
|
13,329 |
|
|
|
18,015 |
|
Cash in Reserve |
|
|
|
|
|
|
1 |
|
|
|
73 |
|
Other Assets |
|
|
|
|
|
|
366 |
|
|
|
394 |
|
Risk Management |
|
|
(Note 21 |
) |
|
|
11 |
|
|
|
65 |
|
Deferred Income Taxes |
|
|
|
|
|
|
377 |
|
|
|
296 |
|
Goodwill |
|
|
(Notes 3, 4, 5 |
) |
|
|
2,862 |
|
|
|
2,917 |
|
|
|
|
(Note 3 |
) |
|
$ |
19,043 |
|
|
$ |
24,621 |
|
|
|
|
|
Liabilities and Shareholders Equity |
|
|
|
|
|
|
|
|
|
|
|
|
Current Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable and accrued liabilities |
|
|
|
|
|
$ |
1,744 |
|
|
$ |
2,243 |
|
Income tax payable |
|
|
|
|
|
|
2 |
|
|
|
15 |
|
Risk management |
|
|
(Note 21 |
) |
|
|
26 |
|
|
|
20 |
|
Deferred income taxes |
|
|
|
|
|
|
35 |
|
|
|
128 |
|
|
|
|
|
|
|
|
1,807 |
|
|
|
2,406 |
|
Long-Term Debt |
|
|
(Note 10 |
) |
|
|
6,112 |
|
|
|
7,340 |
|
Other Liabilities and Provisions |
|
|
(Note 11 |
) |
|
|
2,268 |
|
|
|
2,484 |
|
Risk Management |
|
|
(Note 21 |
) |
|
|
15 |
|
|
|
7 |
|
Asset Retirement Obligation |
|
|
(Note 12 |
) |
|
|
765 |
|
|
|
870 |
|
Deferred Income Taxes |
|
|
|
|
|
|
259 |
|
|
|
1,829 |
|
|
|
|
|
|
|
|
11,226 |
|
|
|
14,936 |
|
Commitments and Contingencies |
|
|
(Note 22 |
) |
|
|
|
|
|
|
|
|
Shareholders Equity |
|
|
|
|
|
|
|
|
|
|
|
|
Share capital - authorized unlimited common shares, without par value 2015 issued and outstanding: 842.5 million shares (2014:
741.2 million shares) |
|
|
(Note 13 |
) |
|
|
3,580 |
|
|
|
2,450 |
|
Paid in surplus |
|
|
(Notes 15, 18 |
) |
|
|
1,358 |
|
|
|
1,358 |
|
Retained earnings |
|
|
|
|
|
|
1,764 |
|
|
|
5,188 |
|
Accumulated other comprehensive income |
|
|
(Note 14 |
) |
|
|
1,115 |
|
|
|
689 |
|
Total Shareholders Equity |
|
|
|
|
|
|
7,817 |
|
|
|
9,685 |
|
|
|
|
|
|
|
$ |
19,043 |
|
|
$ |
24,621 |
|
See accompanying Notes to Condensed Consolidated Financial Statements
|
|
|
|
|
Condensed Consolidated Financial Statements
Prepared in accordance with U.S. GAAP in US$ |
|
|
|
Q2 Report | For the period ended June 30, 2015
|
Condensed Consolidated Statement of Changes in Shareholders Equity (unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 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) |
|
|
|
|
|
|
- |
|
|
|
- |
|
|
|
(3,317) |
|
|
|
- |
|
|
|
- |
|
|
|
(3,317) |
|
|
|
|
|
|
|
|
|
Dividends on Common Shares |
|
|
(Note 13) |
|
|
|
- |
|
|
|
- |
|
|
|
(107) |
|
|
|
- |
|
|
|
- |
|
|
|
(107) |
|
|
|
|
|
|
|
|
|
Common Shares Issued |
|
|
(Note 13) |
|
|
|
1,098 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
1,098 |
|
|
|
|
|
|
|
|
|
Common Shares Issued Under Dividend Reinvestment Plan |
|
|
(Note 13) |
|
|
|
32 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
32 |
|
|
|
|
|
|
|
|
|
Other Comprehensive Income |
|
|
(Note 14) |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
426 |
|
|
|
- |
|
|
|
426 |
|
|
|
|
|
|
|
|
|
Balance, June 30, 2015 |
|
|
|
|
|
$ |
3,580 |
|
|
$ |
1,358 |
|
|
$ |
1,764 |
|
|
$ |
1,115 |
|
|
$ |
- |
|
|
$ |
7,817 |
|
|
|
|
|
|
|
|
|
Six Months Ended June 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 |
|
|
|
|
|
|
- |
|
|
|
- |
|
|
|
387 |
|
|
|
- |
|
|
|
10 |
|
|
|
397 |
|
|
|
|
|
|
|
|
|
Dividends on Common Shares |
|
|
(Note 13) |
|
|
|
- |
|
|
|
- |
|
|
|
(104) |
|
|
|
- |
|
|
|
- |
|
|
|
(104) |
|
|
|
|
|
|
|
|
|
Common Shares Issued Under Dividend Reinvestment Plan |
|
|
(Note 13) |
|
|
|
3 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
3 |
|
|
|
|
|
|
|
|
|
Other Comprehensive Income |
|
|
(Note 14) |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
22 |
|
|
|
- |
|
|
|
22 |
|
|
|
|
|
|
|
|
|
Sale of Noncontrolling Interest |
|
|
(Note 15) |
|
|
|
- |
|
|
|
1,354 |
|
|
|
- |
|
|
|
- |
|
|
|
117 |
|
|
|
1,471 |
|
|
|
|
|
|
|
|
|
Distributions to Noncontrolling Interest Owners |
|
|
(Note 15) |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(6) |
|
|
|
(6) |
|
|
|
|
|
|
|
|
|
Balance, June 30, 2014 |
|
|
|
|
|
$ |
2,448 |
|
|
$ |
1,368 |
|
|
$ |
2,286 |
|
|
$ |
706 |
|
|
$ |
121 |
|
|
$ |
6,929 |
|
See accompanying Notes to Condensed Consolidated Financial Statements
|
|
|
|
|
|
|
Condensed Consolidated Financial Statements
Prepared in accordance with U.S. GAAP in US$ |
|
Q2 Report | For the period ended June 30,
2015 |
Condensed Consolidated Statement of Cash Flows (unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
June 30, |
|
|
Six Months Ended
June 30, |
|
($ millions) |
|
|
|
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
|
Operating Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings (loss) |
|
|
|
|
|
$ |
(1,610 |
) |
|
$ |
281 |
|
|
$ |
(3,317 |
) |
|
$ |
397 |
|
Depreciation, depletion and amortization |
|
|
|
|
|
|
394 |
|
|
|
400 |
|
|
|
860 |
|
|
|
818 |
|
Impairments |
|
|
(Note 9 |
) |
|
|
2,081 |
|
|
|
- |
|
|
|
3,997 |
|
|
|
- |
|
Accretion of asset retirement obligation |
|
|
(Note 12 |
) |
|
|
11 |
|
|
|
13 |
|
|
|
23 |
|
|
|
26 |
|
Deferred income taxes |
|
|
(Note 8 |
) |
|
|
(903 |
) |
|
|
308 |
|
|
|
(1,866 |
) |
|
|
320 |
|
Unrealized (gain) loss on risk management |
|
|
(Note 21 |
) |
|
|
278 |
|
|
|
(9 |
) |
|
|
414 |
|
|
|
276 |
|
Unrealized foreign exchange (gain) loss |
|
|
(Note 7 |
) |
|
|
(245 |
) |
|
|
(178 |
) |
|
|
314 |
|
|
|
19 |
|
Foreign exchange on settlements |
|
|
(Note 7 |
) |
|
|
137 |
|
|
|
1 |
|
|
|
235 |
|
|
|
27 |
|
(Gain) loss on divestitures |
|
|
(Note 5 |
) |
|
|
(2 |
) |
|
|
(204 |
) |
|
|
(16 |
) |
|
|
(203 |
) |
Other |
|
|
|
|
|
|
40 |
|
|
|
44 |
|
|
|
32 |
|
|
|
70 |
|
Net change in other assets and liabilities |
|
|
|
|
|
|
7 |
|
|
|
(8 |
) |
|
|
- |
|
|
|
(17 |
) |
Net change in non-cash working capital |
|
|
|
|
|
|
110 |
|
|
|
119 |
|
|
|
104 |
|
|
|
(23 |
) |
Cash From (Used in) Operating Activities |
|
|
|
|
|
|
298 |
|
|
|
767 |
|
|
|
780 |
|
|
|
1,710 |
|
Investing Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures |
|
|
(Note 3 |
) |
|
|
(743 |
) |
|
|
(560 |
) |
|
|
(1,479 |
) |
|
|
(1,071 |
) |
Acquisitions |
|
|
(Note 5 |
) |
|
|
(3 |
) |
|
|
(2,923 |
) |
|
|
(38 |
) |
|
|
(2,946 |
) |
Proceeds from divestitures |
|
|
(Note 5 |
) |
|
|
143 |
|
|
|
2,271 |
|
|
|
1,016 |
|
|
|
2,318 |
|
Cash in reserve |
|
|
|
|
|
|
43 |
|
|
|
(215 |
) |
|
|
72 |
|
|
|
(212 |
) |
Net change in investments and other |
|
|
|
|
|
|
(121 |
) |
|
|
(62 |
) |
|
|
16 |
|
|
|
(24 |
) |
Cash From (Used in) Investing Activities |
|
|
|
|
|
|
(681 |
) |
|
|
(1,489 |
) |
|
|
(413 |
) |
|
|
(1,935 |
) |
Financing Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net issuance (repayment) of revolving long-term debt |
|
|
|
|
|
|
186 |
|
|
|
- |
|
|
|
120 |
|
|
|
- |
|
Repayment of long-term debt |
|
|
(Note 10 |
) |
|
|
(1,302 |
) |
|
|
(232 |
) |
|
|
(1,302 |
) |
|
|
(1,002 |
) |
Issuance of common shares |
|
|
(Note 13 |
) |
|
|
- |
|
|
|
- |
|
|
|
1,088 |
|
|
|
- |
|
Dividends on common shares |
|
|
(Note 13 |
) |
|
|
(37 |
) |
|
|
(50 |
) |
|
|
(75 |
) |
|
|
(101 |
) |
Proceeds from sale of noncontrolling interest |
|
|
(Note 15 |
) |
|
|
- |
|
|
|
1,471 |
|
|
|
- |
|
|
|
1,471 |
|
Capital lease payments and other financing arrangements |
|
|
(Note 11 |
) |
|
|
(17 |
) |
|
|
(18 |
) |
|
|
(33 |
) |
|
|
(42 |
) |
Cash From (Used in) Financing Activities |
|
|
|
|
|
|
(1,170 |
) |
|
|
1,171 |
|
|
|
(202 |
) |
|
|
326 |
|
Foreign Exchange Gain (Loss) on Cash and Cash Equivalents Held in Foreign Currency |
|
|
|
|
|
|
19 |
|
|
|
47 |
|
|
|
(7 |
) |
|
|
(9 |
) |
Increase (Decrease) in Cash and Cash Equivalents |
|
|
|
|
|
|
(1,534 |
) |
|
|
496 |
|
|
|
158 |
|
|
|
92 |
|
Cash and Cash Equivalents, Beginning of Period |
|
|
|
|
|
|
2,030 |
|
|
|
2,162 |
|
|
|
338 |
|
|
|
2,566 |
|
Cash and Cash Equivalents, End of Period |
|
|
|
|
|
$ |
496 |
|
|
$ |
2,658 |
|
|
$ |
496 |
|
|
$ |
2,658 |
|
|
|
|
|
|
|
Cash, End of Period |
|
|
|
|
|
$ |
86 |
|
|
$ |
107 |
|
|
$ |
86 |
|
|
$ |
107 |
|
Cash Equivalents, End of Period |
|
|
|
|
|
|
410 |
|
|
|
2,551 |
|
|
|
410 |
|
|
|
2,551 |
|
Cash and Cash Equivalents, End of Period |
|
|
|
|
|
$ |
496 |
|
|
$ |
2,658 |
|
|
$ |
496 |
|
|
$ |
2,658 |
|
See accompanying Notes to Condensed Consolidated Financial Statements
|
|
|
|
|
Condensed Consolidated Financial Statements
Prepared in accordance with U.S. GAAP in US$ |
|
|
|
Q2 Report | For the period ended June 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$ |
|
Q2 Report | For the period ended June 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. The amendments will be applied retrospectively. As at June 30, 2015, $34 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, 2017, 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. The
standard can be applied using either the full retrospective approach or a modified retrospective approach 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$ |
|
|
|
Q2 Report | For the period ended June 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 June 30)
Segment and
Geographic Information
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
|
USA Operations |
|
|
Market Optimization |
|
|
|
2015 |
|
2014 |
|
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
|
Revenues, Net of Royalties |
|
$ 387 |
|
$ |
754 |
|
|
$ |
629 |
|
|
$ |
638 |
|
|
$ |
88 |
|
|
$ |
160 |
|
|
|
|
|
|
|
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and mineral taxes |
|
- |
|
|
4 |
|
|
|
26 |
|
|
|
29 |
|
|
|
- |
|
|
|
- |
|
Transportation and processing |
|
171 |
|
|
225 |
|
|
|
144 |
|
|
|
177 |
|
|
|
- |
|
|
|
- |
|
Operating |
|
45 |
|
|
78 |
|
|
|
151 |
|
|
|
79 |
|
|
|
8 |
|
|
|
13 |
|
Purchased product |
|
- |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
79 |
|
|
|
142 |
|
|
|
171 |
|
|
447 |
|
|
|
308 |
|
|
|
353 |
|
|
|
1 |
|
|
|
5 |
|
Depreciation, depletion and amortization |
|
68 |
|
|
165 |
|
|
|
301 |
|
|
|
203 |
|
|
|
- |
|
|
|
1 |
|
Impairments |
|
- |
|
|
- |
|
|
|
2,081 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
$ 103 |
|
$ |
282 |
|
|
$ |
(2,074 |
) |
|
$ |
150 |
|
|
$ |
1 |
|
|
$ |
4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate & Other |
|
|
Consolidated |
|
|
|
|
|
|
|
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
|
Revenues, Net of Royalties |
|
|
|
|
|
|
|
$ |
(274 |
) |
|
$ |
36 |
|
|
$ |
830 |
|
|
$ |
1,588 |
|
|
|
|
|
|
|
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and mineral taxes |
|
|
|
|
|
|
|
|
- |
|
|
|
- |
|
|
|
26 |
|
|
|
33 |
|
Transportation and processing |
|
|
|
|
|
|
|
|
(15 |
) |
|
|
(2 |
) |
|
|
300 |
|
|
|
400 |
|
Operating |
|
|
|
|
|
|
|
|
5 |
|
|
|
8 |
|
|
|
209 |
|
|
|
178 |
|
Purchased product |
|
|
|
|
|
|
|
|
- |
|
|
|
- |
|
|
|
79 |
|
|
|
142 |
|
|
|
|
|
|
|
|
|
|
(264 |
) |
|
|
30 |
|
|
|
216 |
|
|
|
835 |
|
Depreciation, depletion and amortization |
|
|
|
|
|
|
|
|
25 |
|
|
|
31 |
|
|
|
394 |
|
|
|
400 |
|
Impairments |
|
|
|
|
|
|
|
|
- |
|
|
|
- |
|
|
|
2,081 |
|
|
|
- |
|
|
|
|
|
|
|
|
|
$ |
(289) |
|
|
$ |
(1 |
) |
|
|
(2,259 |
) |
|
|
435 |
|
Accretion of asset retirement obligation |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
11 |
|
|
|
13 |
|
Administrative |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
84 |
|
|
|
98 |
|
Interest |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
278 |
|
|
|
122 |
|
Foreign exchange (gain) loss, net |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(86 |
) |
|
|
(172 |
) |
(Gain) loss on divestitures |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2 |
) |
|
|
(204 |
) |
Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4 |
|
|
|
8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
289 |
|
|
|
(135 |
) |
Net Earnings (Loss) Before Income Tax |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,548 |
) |
|
|
570 |
|
Income tax expense (recovery) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(938 |
) |
|
|
289 |
|
Net Earnings (Loss) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,610 |
) |
|
|
281 |
|
Net earnings attributable to noncontrolling interest |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
- |
|
|
|
(10 |
) |
Net Earnings (Loss) Attributable to Common Shareholders |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(1,610 |
) |
|
$ |
271 |
|
Intersegment Information
|
|
|
|
|
|
Market Optimization |
|
|
|
Marketing Sales |
|
|
Upstream Eliminations |
|
|
Total |
|
|
|
2015 |
|
2014 |
|
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
|
Revenues, Net of Royalties |
|
$ 1,117 |
|
$ |
1,781 |
|
|
$ |
(1,029 |
) |
|
$ |
(1,621 |
) |
|
$ |
88 |
|
|
$ |
160 |
|
|
|
|
|
|
|
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transportation and processing |
|
89 |
|
|
123 |
|
|
|
(89 |
) |
|
|
(123 |
) |
|
|
- |
|
|
|
- |
|
Operating |
|
8 |
|
|
19 |
|
|
|
- |
|
|
|
(6 |
) |
|
|
8 |
|
|
|
13 |
|
Purchased product |
|
1,019 |
|
|
1,633 |
|
|
|
(940 |
) |
|
|
(1,491 |
) |
|
|
79 |
|
|
|
142 |
|
Operating Cash Flow |
|
$ 1 |
|
$ |
6 |
|
|
$ |
- |
|
|
$ |
(1 |
) |
|
$ |
1 |
|
|
$ |
5 |
|
|
|
|
|
|
|
|
Notes to Condensed Consolidated Financial Statements
Prepared in accordance with U.S. GAAP in US$ |
|
Q2 Report | For the period ended June 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 six months ended June 30)
Segment and Geographic Information
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
|
USA Operations |
|
|
Market Optimization |
|
|
|
2015 |
|
2014 |
|
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
|
|
Revenues, Net of Royalties |
|
$ 1,019 |
|
$ |
1,947 |
|
|
$ |
1,217 |
|
|
$ |
1,351 |
|
|
$ |
227 |
|
|
$ |
404 |
|
|
|
|
|
|
|
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and mineral taxes |
|
- |
|
|
9 |
|
|
|
45 |
|
|
|
71 |
|
|
|
- |
|
|
|
- |
|
Transportation and processing |
|
348 |
|
|
440 |
|
|
|
299 |
|
|
|
340 |
|
|
|
- |
|
|
|
- |
|
Operating |
|
87 |
|
|
170 |
|
|
|
276 |
|
|
|
153 |
|
|
|
24 |
|
|
|
26 |
|
Purchased product |
|
- |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
200 |
|
|
|
370 |
|
|
|
584 |
|
|
1,328 |
|
|
|
597 |
|
|
|
787 |
|
|
|
3 |
|
|
|
8 |
|
Depreciation, depletion and amortization |
|
173 |
|
|
337 |
|
|
|
637 |
|
|
|
415 |
|
|
|
- |
|
|
|
4 |
|
Impairments |
|
- |
|
|
- |
|
|
|
3,997 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
$ 411 |
|
$ |
991 |
|
|
$ |
(4,037 |
) |
|
$ |
372 |
|
|
$ |
3 |
|
|
$ |
4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate & Other |
|
|
Consolidated |
|
|
|
|
|
|
|
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
|
|
Revenues, Net of Royalties |
|
|
|
|
|
|
|
$ |
(384 |
) |
|
$ |
(222 |
) |
|
$ |
2,079 |
|
|
$ |
3,480 |
|
|
|
|
|
|
|
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and mineral taxes |
|
|
|
|
|
|
|
|
- |
|
|
|
- |
|
|
|
45 |
|
|
|
80 |
|
Transportation and processing |
|
|
|
|
|
|
|
|
(7 |
) |
|
|
(1 |
) |
|
|
640 |
|
|
|
779 |
|
Operating |
|
|
|
|
|
|
|
|
11 |
|
|
|
18 |
|
|
|
398 |
|
|
|
367 |
|
Purchased product |
|
|
|
|
|
|
|
|
- |
|
|
|
- |
|
|
|
200 |
|
|
|
370 |
|
|
|
|
|
|
|
|
|
|
(388 |
) |
|
|
(239 |
) |
|
|
796 |
|
|
|
1,884 |
|
Depreciation, depletion and amortization |
|
|
|
|
|
|
|
|
50 |
|
|
|
62 |
|
|
|
860 |
|
|
|
818 |
|
Impairments |
|
|
|
|
|
|
|
|
- |
|
|
|
- |
|
|
|
3,997 |
|
|
|
- |
|
|
|
|
|
|
|
|
|
$ |
(438 |
) |
|
$ |
(301 |
) |
|
|
(4,061 |
) |
|
|
1,066 |
|
Accretion of asset retirement obligation |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
23 |
|
|
|
26 |
|
Administrative |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
156 |
|
|
|
200 |
|
Interest |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
403 |
|
|
|
269 |
|
Foreign exchange (gain) loss, net |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
570 |
|
|
|
52 |
|
(Gain) loss on divestitures |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(16 |
) |
|
|
(203 |
) |
Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5 |
|
|
|
8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,141 |
|
|
|
352 |
|
Net Earnings (Loss) Before Income Tax |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(5,202 |
) |
|
|
714 |
|
Income tax expense (recovery) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,885 |
) |
|
|
317 |
|
Net Earnings (Loss) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3,317 |
) |
|
|
397 |
|
Net earnings attributable to noncontrolling interest |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
- |
|
|
|
(10 |
) |
Net Earnings (Loss) Attributable to Common Shareholders |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(3,317 |
) |
|
$ |
387 |
|
Intersegment Information
|
|
|
|
Market Optimization |
|
|
|
Marketing Sales |
|
|
Upstream Eliminations |
|
|
Total |
|
|
|
2015 |
|
2014 |
|
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
|
|
Revenues, Net of Royalties |
|
$ 2,282 |
|
$ |
4,008 |
|
|
$ |
(2,055 |
) |
|
$ |
(3,604 |
) |
|
$ |
227 |
|
|
$ |
404 |
|
|
|
|
|
|
|
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transportation and processing |
|
184 |
|
|
250 |
|
|
|
(184 |
) |
|
|
(250 |
) |
|
|
- |
|
|
|
- |
|
Operating |
|
24 |
|
|
44 |
|
|
|
- |
|
|
|
(18 |
) |
|
|
24 |
|
|
|
26 |
|
Purchased product |
|
2,071 |
|
|
3,703 |
|
|
|
(1,871 |
) |
|
|
(3,333 |
) |
|
|
200 |
|
|
|
370 |
|
Operating Cash Flow |
|
$ 3 |
|
$ |
11 |
|
|
$ |
- |
|
|
$ |
(3 |
) |
|
$ |
3 |
|
|
$ |
8 |
|
|
|
|
|
|
Notes to Condensed Consolidated Financial Statements
Prepared in accordance with U.S. GAAP in US$ |
|
|
|
Q2 Report | For the period ended June 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
June 30, |
|
|
Six Months Ended
June 30, |
|
|
|
|
|
|
|
|
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
|
|
Canadian Operations |
|
|
|
|
|
|
|
|
|
$ |
114 |
|
|
$ |
350 |
|
|
$ |
265 |
|
|
$ |
631 |
|
USA Operations |
|
|
|
|
|
|
|
|
|
|
628 |
|
|
|
206 |
|
|
|
1,211 |
|
|
|
432 |
|
Market Optimization |
|
|
|
|
|
|
|
|
|
|
- |
|
|
|
1 |
|
|
|
- |
|
|
|
2 |
|
Corporate & Other |
|
|
|
|
|
|
|
|
|
|
1 |
|
|
|
3 |
|
|
|
3 |
|
|
|
6 |
|
|
|
|
|
|
|
|
|
|
|
$ |
743 |
|
|
$ |
560 |
|
|
$ |
1,479 |
|
|
$ |
1,071 |
|
Goodwill, Property, Plant and Equipment and Total Assets by
Segment |
|
|
|
Goodwill |
|
|
Property, Plant and Equipment |
|
|
Total Assets |
|
|
|
As at |
|
|
As at |
|
|
As at |
|
|
|
June 30, 2015 |
|
|
December 31, 2014 |
|
|
June 30, 2015 |
|
|
December 31, 2014 |
|
|
June 30, 2015 |
|
|
December 31, 2014 |
|
|
|
|
|
|
|
|
Canadian Operations |
|
$ |
733 |
|
|
$ |
788 |
|
|
$ |
1,320 |
|
|
$ |
2,338 |
|
|
$ |
2,413 |
|
|
$ |
3,632 |
|
USA Operations |
|
|
2,129 |
|
|
|
2,129 |
|
|
|
10,311 |
|
|
|
13,817 |
|
|
|
12,749 |
|
|
|
16,800 |
|
Market Optimization |
|
|
- |
|
|
|
- |
|
|
|
1 |
|
|
|
1 |
|
|
|
35 |
|
|
|
181 |
|
Corporate & Other |
|
|
- |
|
|
|
- |
|
|
|
1,697 |
|
|
|
1,859 |
|
|
|
3,846 |
|
|
|
4,008 |
|
|
|
$ |
2,862 |
|
|
$ |
2,917 |
|
|
$ |
13,329 |
|
|
$ |
18,015 |
|
|
$ |
19,043 |
|
|
$ |
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 $1.15 billion senior notes were redeemed in accordance with the provisions of the governing indentures. Athlons operations focused on the acquisition and development of oil and gas properties
located in the Permian Basin in Texas.
|
|
|
|
|
|
|
Notes to Condensed Consolidated Financial Statements
Prepared in accordance with U.S. GAAP in US$ |
|
Q2 Report | For the period ended June 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 first or second quarters of 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 $5.93 billion, as well as payments to terminate certain employment agreements
with Athlons management and payments for certain other existing obligations of Athlon. |
The Company used the income approach
valuation technique for the fair value of assets acquired and liabilities assumed. The carrying amounts of cash, accounts receivable and other current assets, and accounts payable and accrued liabilities approximate their fair values due to the
short-term maturity of the instruments. The fair values of the risk management assets and long-term debt, including the revolving credit facility, are categorized within Level 2 of the fair value hierarchy and were determined using quoted prices and
rates from an available pricing source. The fair values of the proved and unproved properties, other property, plant and equipment, other assets, goodwill, and asset retirement obligation are categorized within Level 3 and were determined using
relevant market assumptions, including discount rates, future commodity prices and costs, timing of development activities, projections of oil and gas reserves, and estimates to abandon and reclaim producing wells.
Goodwill arose from the Athlon acquisition primarily from the requirement to recognize deferred taxes on the difference between the fair value of the
assets acquired and liabilities assumed and the respective carry-over tax basis. Goodwill is not amortized and is not deductible for tax purposes.
|
|
|
|
|
Notes to Condensed Consolidated Financial Statements
Prepared in accordance with U.S. GAAP in US$ |
|
|
|
Q2 Report | For the period ended June 30, 2015
|
|
Notes to Condensed Consolidated Financial Statements (unaudited) |
(All amounts in $ millions unless otherwise specified)
|
4. Business Combinations (continued) |
Unaudited 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 six months ended June 30, 2015 include the results from Eagle Ford and
Athlon.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, 2014 ($ millions, except per share amounts) |
|
|
|
|
|
|
|
Eagle Ford |
|
|
Athlon |
|
|
|
|
|
|
Revenues, Net of Royalties |
|
|
|
|
|
|
|
|
|
$ |
4,221 |
|
|
$ |
3,678 |
|
Net Earnings |
|
|
|
|
|
|
|
|
|
$ |
650 |
|
|
$ |
377 |
|
Net Earnings per Common Share |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic & Diluted |
|
|
|
|
|
|
|
|
|
$ |
0.88 |
|
|
$ |
0.51 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5. Acquisitions and Divestitures |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
June 30, |
|
|
Six Months Ended
June 30, |
|
|
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
Acquisitions |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
$ |
1 |
|
|
$ |
- |
|
|
$ |
1 |
|
|
$ |
2 |
|
USA Operations |
|
|
2 |
|
|
|
2,923 |
|
|
|
3 |
|
|
|
2,944 |
|
Corporate & Other |
|
|
- |
|
|
|
- |
|
|
|
34 |
|
|
|
- |
|
Total Acquisitions |
|
|
3 |
|
|
|
2,923 |
|
|
|
38 |
|
|
|
2,946 |
|
|
|
|
|
|
Divestitures |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
|
(50 |
) |
|
|
(89 |
) |
|
|
(879 |
) |
|
|
(121 |
) |
USA Operations |
|
|
(87 |
) |
|
|
(2,156 |
) |
|
|
(84 |
) |
|
|
(2,170 |
) |
Corporate & Other |
|
|
(6 |
) |
|
|
(26 |
) |
|
|
(53 |
) |
|
|
(27 |
) |
Total Divestitures |
|
|
(143 |
) |
|
|
(2,271 |
) |
|
|
(1,016 |
) |
|
|
(2,318 |
) |
Net Acquisitions & (Divestitures) |
|
$ |
(140 |
) |
|
$ |
652 |
|
|
$ |
(978 |
) |
|
$ |
628 |
|
Acquisitions
During the
three and six months ended June 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 six months ended
June 30, 2015, divestitures in the Canadian Operations were $50 million and $879 million, respectively (2014 - $89 million and $121 million, respectively). Divestitures primarily included 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$454 million ($358 million), after closing adjustments and the sale of land and properties that do not complement Encanas existing portfolio of assets.
For the three and six months ended June 30, 2015, divestitures in the USA Operations were $87 million and $84 million, respectively, which
primarily included the sale of land and properties that do not complement Encanas existing portfolio of assets. During the three and six months ended June 30, 2014, divestitures in the USA Operations were $2,156 million and $2,170
million, respectively, which 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 $427 million, after closing adjustments.
The proved reserves associated with the Jonah divestiture exceeded 25 percent of Encanas proved reserves in the U.S. cost centre. The
carrying amount of the assets was deducted from the full cost pool and the remainder of the proceeds was recognized as a gain on sale of approximately $212 million, before tax. For divestitures that result in a gain or loss on sale and constitute a
business, goodwill is assigned to the transaction. Accordingly, goodwill of $68 million was allocated to the Jonah divestiture.
Amounts received
from the divestiture transactions have been deducted from the respective Canadian and U.S. full cost pools, except for the Jonah divestiture as noted above.
For the six months ended June 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 $12 million.
|
|
|
|
|
|
|
Notes to Condensed Consolidated Financial Statements
Prepared in accordance with U.S. GAAP in US$ |
|
Q2 Report | For the period ended June 30,
2015 |
|
Notes to Condensed Consolidated Financial Statements (unaudited) |
(All amounts in $ millions unless otherwise specified)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
June 30, |
|
|
Six Months Ended
June 30, |
|
|
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
Interest Expense on: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Debt |
|
$ |
248 |
|
|
$ |
96 |
|
|
$ |
343 |
|
|
$ |
208 |
|
The Bow office building |
|
|
18 |
|
|
|
19 |
|
|
|
34 |
|
|
|
38 |
|
Capital leases |
|
|
6 |
|
|
|
10 |
|
|
|
15 |
|
|
|
19 |
|
Other |
|
|
6 |
|
|
|
(3 |
) |
|
|
11 |
|
|
|
4 |
|
|
|
$ |
278 |
|
|
$ |
122 |
|
|
$ |
403 |
|
|
$ |
269 |
|
|
Interest Expense on Debt for the three and six months ended June 30, 2015 includes a one-time interest payment of
approximately $165 million resulting from the 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
June 30, |
|
|
Six Months Ended
June 30, |
|
|
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
Unrealized Foreign Exchange (Gain) Loss on: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Translation of U.S. dollar debt issued from Canada |
|
$ |
(123 |
) |
|
$ |
(184 |
) |
|
$ |
341 |
|
|
$ |
20 |
|
Translation of U.S. dollar risk management contracts issued from Canada |
|
|
6 |
|
|
|
6 |
|
|
|
(29 |
) |
|
|
(1 |
) |
Translation of intercompany notes |
|
|
(128 |
) |
|
|
- |
|
|
|
2 |
|
|
|
- |
|
|
|
|
(245 |
) |
|
|
(178 |
) |
|
|
314 |
|
|
|
19 |
|
Foreign Exchange on Settlements |
|
|
137 |
|
|
|
1 |
|
|
|
235 |
|
|
|
27 |
|
Other Monetary Revaluations |
|
|
22 |
|
|
|
5 |
|
|
|
21 |
|
|
|
6 |
|
|
|
$ |
(86 |
) |
|
$ |
(172 |
) |
|
$ |
570 |
|
|
$ |
52 |
|
|
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
June 30, |
|
|
Six Months Ended
June 30, |
|
|
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
Current Tax |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada |
|
$ |
(38 |
) |
|
$ |
(27 |
) |
|
$ |
(25 |
) |
|
$ |
(20 |
) |
United States |
|
|
2 |
|
|
|
4 |
|
|
|
3 |
|
|
|
7 |
|
Other countries |
|
|
1 |
|
|
|
4 |
|
|
|
3 |
|
|
|
10 |
|
Total Current Tax Expense (Recovery) |
|
|
(35 |
) |
|
|
(19 |
) |
|
|
(19 |
) |
|
|
(3 |
) |
|
|
|
|
|
Deferred Tax |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada |
|
|
(155 |
) |
|
|
224 |
|
|
|
(478 |
) |
|
|
228 |
|
United States |
|
|
(879 |
) |
|
|
69 |
|
|
|
(1,639 |
) |
|
|
71 |
|
Other countries |
|
|
131 |
|
|
|
15 |
|
|
|
251 |
|
|
|
21 |
|
Total Deferred Tax Expense (Recovery) |
|
|
(903 |
) |
|
|
308 |
|
|
|
(1,866 |
) |
|
|
320 |
|
|
|
$ |
(938 |
) |
|
$ |
289 |
|
|
$ |
(1,885 |
) |
|
$ |
317 |
|
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$ |
|
|
|
Q2 Report | For the period ended June 30, 2015
|
|
Notes to Condensed Consolidated Financial Statements (unaudited) |
(All amounts in $ millions unless otherwise specified)
|
9. Property, Plant and Equipment, Net |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As at June 30, 2015 |
|
|
As at December 31, 2014 |
|
|
|
Cost |
|
|
Accumulated
DD&A (1) |
|
|
Net |
|
|
Cost |
|
|
Accumulated
DD&A (1) |
|
|
Net |
|
|
|
|
|
|
|
|
Canadian Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved properties |
|
$ |
16,361 |
|
|
$ |
(15,581) |
|
|
$ |
780 |
|
|
$ |
18,271 |
|
|
$ |
(16,566) |
|
|
$ |
1,705 |
|
Unproved properties |
|
|
420 |
|
|
|
- |
|
|
|
420 |
|
|
|
478 |
|
|
|
- |
|
|
|
478 |
|
Other |
|
|
120 |
|
|
|
- |
|
|
|
120 |
|
|
|
155 |
|
|
|
- |
|
|
|
155 |
|
|
|
|
16,901 |
|
|
|
(15,581) |
|
|
|
1,320 |
|
|
|
18,904 |
|
|
|
(16,566) |
|
|
|
2,338 |
|
|
|
|
|
|
|
|
USA Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved properties |
|
|
25,662 |
|
|
|
(20,891) |
|
|
|
4,771 |
|
|
|
24,279 |
|
|
|
(16,260) |
|
|
|
8,019 |
|
Unproved properties |
|
|
5,435 |
|
|
|
- |
|
|
|
5,435 |
|
|
|
5,655 |
|
|
|
- |
|
|
|
5,655 |
|
Other |
|
|
105 |
|
|
|
- |
|
|
|
105 |
|
|
|
143 |
|
|
|
- |
|
|
|
143 |
|
|
|
|
31,202 |
|
|
|
(20,891) |
|
|
|
10,311 |
|
|
|
30,077 |
|
|
|
(16,260) |
|
|
|
13,817 |
|
|
|
|
|
|
|
|
Market Optimization |
|
|
8 |
|
|
|
(7) |
|
|
|
1 |
|
|
|
8 |
|
|
|
(7) |
|
|
|
1 |
|
Corporate & Other |
|
|
2,306 |
|
|
|
(609) |
|
|
|
1,697 |
|
|
|
2,470 |
|
|
|
(611) |
|
|
|
1,859 |
|
|
|
$ |
50,417 |
|
|
$ |
(37,088) |
|
|
$ |
13,329 |
|
|
$ |
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 $128 million which have been
capitalized during the six months ended June 30, 2015 (2014 - $195 million). Included in Corporate and Other are $61 million ($65 million as at December 31, 2014) of international property costs, which have been fully impaired.
For the three and six months ended June 30,
2015, the Company recognized before-tax ceiling test impairments of $2,081 million and $3,997 million, respectively (2014 - nil) in the U.S. cost centre, which are included within accumulated DD&A in the table above. The impairments resulted
primarily from the decline in the 12-month average trailing commodity prices which reduced proved reserves volumes and values. There were no ceiling test impairments in the Canadian cost centre for the three and six months ended June 30, 2015
(2014 - nil).
The 12-month average
trailing prices used in the ceiling test calculations were based on the benchmark prices below. The benchmark prices were adjusted for basis differentials to determine local reference prices, transportation costs and tariffs, heat content and
quality.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas |
|
|
Oil & NGLs |
|
|
|
|
|
|
|
|
Henry Hub ($/MMBtu) |
|
|
AECO (C$/MMBtu) |
|
|
WTI ($/bbl) |
|
|
Edmonton Light Sweet
(C$/bbl) |
|
|
|
12-Month Average Trailing Reserves Pricing |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2015 |
|
|
3.38 |
|
|
|
3.32 |
|
|
|
71.68 |
|
|
|
75.58 |
|
December 31, 2014 |
|
|
4.34 |
|
|
|
4.63 |
|
|
|
94.99 |
|
|
|
96.40 |
|
June 30, 2014 |
|
|
4.10 |
|
|
|
4.11 |
|
|
|
100.27 |
|
|
|
98.20 |
|
|
|
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 June 30, 2015, the total carrying value of assets under capital lease was $443 million ($547
million as at December 31, 2014). Liabilities for the capital lease arrangements are included in other liabilities and provisions in the Condensed Consolidated Balance Sheet and are disclosed in Note 11.
|
|
|
|
|
|
|
Notes to Condensed Consolidated Financial Statements
Prepared in accordance with U.S. GAAP in US$ |
|
Q2 Report | For the period ended June 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 June 30, 2015, Corporate and
Other property, plant and equipment and total assets include a carrying value of $1,319 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 June 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 |
|
|
|
|
|
|
1,397 |
|
|
|
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 |
|
|
|
|
|
|
|
|
6,097 |
|
|
|
6,677 |
|
Total Principal |
|
|
|
|
|
|
6,097 |
|
|
|
7,324 |
|
|
|
|
|
Increase in Value of Debt Acquired |
|
|
|
|
|
|
31 |
|
|
|
34 |
|
Debt Discounts |
|
|
|
|
|
|
(16 |
) |
|
|
(18 |
) |
Current Portion of Long-Term Debt |
|
|
|
|
|
|
- |
|
|
|
- |
|
|
|
|
|
|
|
$ |
6,112 |
|
|
$ |
7,340 |
|
Long-term debt is accounted for at amortized cost using the effective interest method of amortization. As at
June 30, 2015, total long-term debt had a carrying value of $6,112 million and a fair value of $6,448 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 $7 million of accrued and unpaid interest.
|
|
|
|
|
Notes to Condensed Consolidated Financial Statements
Prepared in accordance with U.S. GAAP in US$ |
|
|
|
Q2 Report | For the period ended June 30, 2015
|
|
Notes to Condensed Consolidated Financial Statements (unaudited) |
(All amounts in $ millions unless otherwise specified)
|
11. Other Liabilities and Provisions |
|
|
|
|
|
|
|
|
|
|
|
As at June 30, 2015 |
|
|
As at December 31, 2014 |
|
|
|
|
The Bow Office Building (See Note 9) |
|
$ |
1,378 |
|
|
$ |
1,486 |
|
Capital Lease Obligations (See Note 9) |
|
|
416 |
|
|
|
473 |
|
Unrecognized Tax Benefits |
|
|
245 |
|
|
|
279 |
|
Pensions and Other Post-Employment Benefits |
|
|
153 |
|
|
|
144 |
|
Long-Term Incentives (See Note 18) |
|
|
32 |
|
|
|
70 |
|
Other |
|
|
44 |
|
|
|
32 |
|
|
|
$ |
2,268 |
|
|
$ |
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 |
|
$ |
37 |
|
|
$ |
75 |
|
|
$ |
76 |
|
|
$ |
76 |
|
|
$ |
77 |
|
|
$ |
1,538 |
|
|
$ |
1,879 |
|
|
|
|
|
|
|
|
|
Sublease Recoveries |
|
$ |
(18 |
) |
|
$ |
(37 |
) |
|
$ |
(37 |
) |
|
$ |
(38 |
) |
|
$ |
(38 |
) |
|
$ |
(755 |
) |
|
$ |
(923 |
) |
|
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 |
|
$ |
49 |
|
|
$ |
98 |
|
|
$ |
99 |
|
|
$ |
99 |
|
|
$ |
99 |
|
|
$ |
232 |
|
|
$ |
676 |
|
Less Amounts Representing |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest |
|
|
21 |
|
|
|
40 |
|
|
|
36 |
|
|
|
32 |
|
|
|
28 |
|
|
|
47 |
|
|
|
204 |
|
Present Value of Expected |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future Lease Payments |
|
$ |
28 |
|
|
$ |
58 |
|
|
$ |
63 |
|
|
$ |
67 |
|
|
$ |
71 |
|
|
$ |
185 |
|
|
$ |
472 |
|
|
|
|
|
|
|
|
Notes to Condensed Consolidated Financial Statements
Prepared in accordance with U.S. GAAP in US$ |
|
Q2 Report | For the period ended June 30,
2015 |
|
Notes to Condensed Consolidated Financial Statements (unaudited) |
(All amounts in $ millions unless otherwise specified)
|
12. Asset Retirement Obligation |
|
|
|
|
|
|
|
|
|
|
|
As at June 30, 2015 |
|
|
As at December 31, 2014 |
|
|
|
|
Asset Retirement Obligation, Beginning of Year |
|
$ |
913 |
|
|
$ |
966 |
|
Liabilities Incurred and Acquired (See Note 4) |
|
|
12 |
|
|
|
85 |
|
Liabilities Settled and Divested |
|
|
(113 |
) |
|
|
(188 |
) |
Change in Estimated Future Cash Outflows |
|
|
- |
|
|
|
35 |
|
Accretion Expense |
|
|
23 |
|
|
|
52 |
|
Foreign Currency Translation |
|
|
(28 |
) |
|
|
(37 |
) |
Asset Retirement Obligation, End of Period |
|
$ |
807 |
|
|
$ |
913 |
|
|
|
|
Current Portion |
|
$ |
42 |
|
|
$ |
43 |
|
Long-Term Portion |
|
|
765 |
|
|
|
870 |
|
|
|
$ |
807 |
|
|
$ |
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
June 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 |
|
|
2.9 |
|
|
|
32 |
|
|
|
0.3 |
|
|
|
5 |
|
Common Shares Outstanding, End of Period |
|
|
842.5 |
|
|
$ |
3,580 |
|
|
|
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 six months ended June 30, 2015, Encana issued 2,872,237 common shares totaling $32 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 June 30, 2015, Encana paid dividends of $0.07 per common share totaling $55 million (2014 - $0.07 per common
share totaling $52 million). During the six months ended June 30, 2015, Encana paid dividends of $0.14 per common share totaling $107 million (2014 - $0.14 per common share totaling $104 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 six months ended June 30,
2015, the dividends paid included $18 million and $32 million, respectively, in common shares issued in lieu of cash dividends under the DRIP (for the three and six months ended June 30, 2014 - $2 million and $3 million, respectively).
|
|
|
|
|
Notes to Condensed Consolidated Financial Statements
Prepared in accordance with U.S. GAAP in US$ |
|
|
|
Q2 Report | For the period ended June 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
June 30, |
|
|
Six Months Ended
June 30, |
|
(millions, except per share amounts) |
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
Net Earnings (Loss) Attributable to Common Shareholders |
|
$ |
(1,610 |
) |
|
$ |
271 |
|
|
$ |
(3,317 |
) |
|
$ |
387 |
|
|
|
|
|
|
Number of Common Shares: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding - Basic |
|
|
841.2 |
|
|
|
741.0 |
|
|
|
799.5 |
|
|
|
741.0 |
|
Effect of dilutive securities |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Weighted average common shares outstanding - Diluted |
|
|
841.2 |
|
|
|
741.0 |
|
|
|
799.5 |
|
|
|
741.0 |
|
|
|
|
|
|
Net Earnings (Loss) per Common Share |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
(1.91 |
) |
|
$ |
0.37 |
|
|
$ |
(4.15 |
) |
|
$ |
0.52 |
|
Diluted |
|
$ |
(1.91 |
) |
|
$ |
0.37 |
|
|
$ |
(4.15 |
) |
|
$ |
0.52 |
|
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 June 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$ |
|
Q2 Report | For the period ended June 30,
2015 |
|
Notes to Condensed Consolidated Financial Statements (unaudited) |
(All amounts in $ millions unless otherwise specified)
|
14. Accumulated Other Comprehensive Income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
June 30, |
|
|
Six Months Ended
June 30, |
|
|
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
Foreign Currency Translation Adjustment |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, Beginning of Period |
|
$ |
1,193 |
|
|
$ |
717 |
|
|
$ |
715 |
|
|
$ |
693 |
|
Current Period Change in Foreign Currency Translation Adjustment |
|
|
(53 |
) |
|
|
(2 |
) |
|
|
425 |
|
|
|
22 |
|
Balance, End of Period |
|
$ |
1,140 |
|
|
$ |
715 |
|
|
$ |
1,140 |
|
|
$ |
715 |
|
|
|
|
|
|
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 |
|
|
|
- |
|
Income Taxes |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Balance, End of Period |
|
$ |
(25 |
) |
|
$ |
(9 |
) |
|
$ |
(25 |
) |
|
$ |
(9 |
) |
Total Accumulated Other Comprehensive Income |
|
$ |
1,115 |
|
|
$ |
706 |
|
|
$ |
1,115 |
|
|
$ |
706 |
|
|
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). As at June 30, 2014, 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 six months ended June 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 $73 million, was recognized as paid in surplus as at June 30, 2014. For the three and six months ended June 30, 2014, net earnings and comprehensive income of $10 million were attributable to the noncontrolling
interest as presented in the Condensed Consolidated Statement of Earnings and Condensed Consolidated Statement of Comprehensive Income, respectively.
Distributions to Noncontrolling Interest Owners
On
June 18, 2014, PrairieSky declared a dividend of C$0.1058 per common share payable on July 15, 2014 to PrairieSky common shareholders totaling $13 million, of which $6 million was attributable to the noncontrolling interest as presented in
the Condensed Consolidated Statement of Changes in Shareholders Equity.
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$2.6 billion. Following the completion of the secondary offering, Encana no longer held an interest in PrairieSky.
|
|
|
|
|
Notes to Condensed Consolidated Financial Statements
Prepared in accordance with U.S. GAAP in US$ |
|
|
|
Q2 Report | For the period ended June 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 to loss is the expected lease payments over the initial contract term. As at June 30, 2015, Encanas capital lease
obligation of $404 million ($462 million as at December 31, 2014) 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 expansion of future midstream services in
support of Encana and the CRPs development of the Montney play. In addition, VMLP will also provide to Encana and the CRP natural gas gathering and processing under existing agreements that were contributed to VMLP by its partner Veresen Inc.,
with 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 take or pay 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.
The total maximum exposure to loss as a result of Encanas involvement with VMLP is estimated to be $1,215 million as at June 30, 2015 and is
based on the future take or pay for volumes committed to certain gathering and processing assets and the potential payout of minimum costs associated with certain gathering and compression assets. The total maximum exposure to loss associated with
the potential payout requirement is highly uncertain as the payout amount is contingent on future production estimates, pace of development and capacity contracted to third parties. As at June 30, 2015, there were no accounts payable and
accrued liabilities outstanding related to the take or pay commitment. The take or pay for volumes committed to certain gathering and processing agreements are included in Note 22.
|
|
|
|
|
|
|
Notes to Condensed Consolidated Financial Statements
Prepared in accordance with U.S. GAAP in US$ |
|
Q2 Report | For the period ended June 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,
the Company has incurred restructuring charges primarily related to severance costs totaling $125 million, of which $2 million remains accrued as at June 30, 2015. Total restructuring charges are expected to be approximately $135 million before
tax. For the six months ended June 30, 2015, $1 million in restructuring charges were incurred (2014 - $22 million). The remaining restructuring charges of approximately $10 million are anticipated to be incurred during the remainder of 2015.
Restructuring charges are included in administrative expense in the Condensed Consolidated Statement of Earnings.
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 $58 million before tax. For the six months ended
June 30, 2015, costs of $30 million were incurred, of which $13 million remains accrued. The remaining transition and severance costs of approximately $28 million are expected to be incurred during the remainder of 2015.
Encana
has a number of compensation arrangements under which the Company awards various types of long-term incentive grants to eligible employees. These primarily include TSARs, Performance TSARs, SARs, Performance SARs, Performance Share Units
(PSUs), Deferred Share Units (DSUs) and RSUs. These compensation arrangements are share-based.
Encana accounts for TSARs,
Performance TSARs, SARs, Performance SARs, PSUs and RSUs held by Encana employees as cash-settled share-based payment transactions and, accordingly, accrues compensation costs over the vesting period based on the fair value of the rights determined
using the Black-Scholes-Merton and other fair value models.
As at June 30, 2015, the following weighted average assumptions were used to
determine the fair value of the share units held by Encana employees:
|
|
|
|
|
|
|
|
|
|
|
Encana US$ Share Units |
|
|
Encana C$ Share Units |
|
|
|
|
Risk Free Interest Rate |
|
|
0.56% |
|
|
|
0.56% |
|
Dividend Yield |
|
|
2.54% |
|
|
|
2.51% |
|
Expected Volatility Rate |
|
|
30.71% |
|
|
|
28.54% |
|
Expected Term |
|
|
1.7 yrs |
|
|
|
1.8 yrs |
|
Market Share Price |
|
|
US$11.02 |
|
|
|
C$13.77 |
|
|
|
|
|
|
Notes to Condensed Consolidated Financial Statements
Prepared in accordance with U.S. GAAP in US$ |
|
|
|
Q2 Report | For the period ended June 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 June 30, |
|
|
Six Months Ended June 30, |
|
|
|
2015 |
|
2014 |
|
|
2015 |
|
2014 |
|
|
|
|
|
|
|
|
Compensation Costs of Transactions Classified as Cash-Settled |
|
$ |
|
13 |
|
$ |
57 |
|
|
$ |
|
7 |
|
$ |
129 |
|
Compensation Costs of Transactions Classified as
Equity-Settled (1) |
|
|
|
- |
|
|
1 |
|
|
|
|
- |
|
|
(1 |
) |
Total Share-Based Compensation Costs |
|
|
|
13 |
|
|
58 |
|
|
|
|
7 |
|
|
128 |
|
Less: Total Share-Based Compensation Costs Capitalized |
|
|
|
(5) |
|
|
(20 |
) |
|
|
|
(2) |
|
|
(46 |
) |
Total Share-Based Compensation Expense |
|
$ |
|
8 |
|
$ |
38 |
|
|
$ |
|
5 |
|
$ |
82 |
|
|
|
|
|
|
|
|
Recognized on the Condensed Consolidated Statement of Earnings in: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating expense |
|
$ |
|
3 |
|
$ |
16 |
|
|
$ |
|
1 |
|
$ |
36 |
|
Administrative expense |
|
|
|
5 |
|
|
22 |
|
|
|
|
4 |
|
|
46 |
|
|
|
$ |
|
8 |
|
$ |
38 |
|
|
$ |
|
5 |
|
$ |
82 |
|
|
(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 June 30, 2015, the liability for share-based payment transactions totaled $95 million ($99 million as at
December 31, 2014), of which $63 million ($29 million as at December 31, 2014) is recognized in accounts payable and accrued liabilities in the Condensed Consolidated Balance Sheet.
|
|
|
|
|
|
|
|
|
|
|
As at June 30, 2015 |
|
|
As at December 31, 2014 |
|
Liability for Cash-Settled Share-Based
Payment Transactions: |
|
|
|
|
|
|
|
|
Unvested |
|
$ |
79 |
|
|
$ |
78 |
|
Vested |
|
|
16 |
|
|
|
21 |
|
|
|
$ |
95 |
|
|
$ |
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.
|
|
|
|
|
Six Months Ended June 30, 2015 (thousands of units) |
|
|
|
|
|
TSARs |
|
|
1,934 |
|
SARs |
|
|
1,444 |
|
PSUs |
|
|
2,319 |
|
DSUs |
|
|
172 |
|
RSUs |
|
|
6,557 |
|
|
|
|
|
|
|
|
Notes to Condensed Consolidated Financial Statements
Prepared in accordance with U.S. GAAP in US$ |
|
Q2 Report | For the period ended June 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
six months ended June 30 as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits |
|
|
OPEB |
|
|
Total |
|
|
|
2015 |
|
2014 |
|
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
|
|
|
Defined Benefit Plan Expense |
|
$ |
|
1 |
|
$ |
- |
|
|
$ |
7 |
|
|
$ |
6 |
|
|
$ |
8 |
|
|
$ |
6 |
|
Defined Contribution Plan Expense |
|
|
|
15 |
|
|
17 |
|
|
|
- |
|
|
|
- |
|
|
|
15 |
|
|
|
17 |
|
Total Benefit Plans Expense |
|
$ |
|
16 |
|
$ |
17 |
|
|
$ |
7 |
|
|
$ |
6 |
|
|
$ |
23 |
|
|
$ |
23 |
|
Of the total benefit plans expense, $18 million
(2014 - $17 million) was included in operating expense and $5 million (2014 - $6 million) was included in administrative expense.
The defined periodic pension and OPEB expense for the six months ended June 30 are as follows:
|
|
|
|
Pension Benefits |
|
|
OPEB |
|
|
Total |
|
|
|
2015 |
|
2014 |
|
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
|
|
|
Current Service Costs |
|
$ |
|
2 |
|
$ |
2 |
|
|
$ |
5 |
|
|
$ |
4 |
|
|
$ |
7 |
|
|
$ |
6 |
|
Interest Cost |
|
|
|
5 |
|
|
6 |
|
|
|
2 |
|
|
|
2 |
|
|
|
7 |
|
|
|
8 |
|
Expected Return On Plan Assets |
|
|
|
(7) |
|
|
(8 |
) |
|
|
- |
|
|
|
- |
|
|
|
(7 |
) |
|
|
(8 |
) |
Amounts Reclassified From Accumulated Other Comprehensive Income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization of net actuarial (gains) and losses |
|
|
|
1 |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
1 |
|
|
|
- |
|
Total Defined Benefit Plan Expense |
|
$ |
|
1 |
|
$ |
- |
|
|
$ |
7 |
|
|
$ |
6 |
|
|
$ |
8 |
|
|
$ |
6 |
|
The amounts recognized in other comprehensive
income for the six months ended June 30 are as follows: |
|
|
|
|
|
|
|
Pension Benefits |
|
|
OPEB |
|
|
Total |
|
|
|
2015 |
|
2014 |
|
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
|
|
|
Total Amounts Recognized in Other Comprehensive (Income) Loss, Before Tax |
|
$ |
|
(1) |
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
(1 |
) |
|
$ |
- |
|
Total Amounts Recognized in Other Comprehensive (Income) Loss, After Tax |
|
$ |
|
(1) |
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
(1 |
) |
|
$ |
- |
|
|
|
|
|
|
Notes to Condensed Consolidated Financial Statements
Prepared in accordance with U.S. GAAP in US$ |
|
|
|
Q2 Report | For the period ended June 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 June 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 |
|
$ |
- |
|
|
$ |
390 |
|
|
$ |
- |
|
|
$ |
390 |
|
|
$ |
(60 |
) |
|
$ |
330 |
|
Long-term |
|
|
- |
|
|
|
14 |
|
|
|
- |
|
|
|
14 |
|
|
|
(3 |
) |
|
|
11 |
|
Risk Management Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current |
|
|
- |
|
|
|
82 |
|
|
|
4 |
|
|
|
86 |
|
|
|
(60 |
) |
|
|
26 |
|
Long-term |
|
|
- |
|
|
|
12 |
|
|
|
6 |
|
|
|
18 |
|
|
|
(3 |
) |
|
|
15 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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$ |
|
Q2 Report | For the period ended June 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 and basis swaps with terms to 2018. 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 June 30, 2015, the Companys Level 3 risk management assets and liabilities consist of power purchase contracts with terms to 2017. 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 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 six months ended June 30 is presented below:
|
|
|
|
|
|
|
|
|
|
|
Risk Management
|
|
|
|
2015 |
|
|
2014 |
|
|
|
|
Balance, Beginning of Year |
|
$ |
(18 |
) |
|
$ |
(7 |
) |
Total Gains (Losses) |
|
|
- |
|
|
|
(3 |
) |
Purchases and Settlements: |
|
|
|
|
|
|
|
|
Purchases |
|
|
- |
|
|
|
- |
|
Settlements |
|
|
8 |
|
|
|
4 |
|
Transfers in and out of Level 3 |
|
|
- |
|
|
|
- |
|
Balance, End of Period |
|
$ |
(10 |
) |
|
$ |
(6 |
) |
Change in unrealized gains (losses) related to |
|
|
|
|
|
|
|
|
assets and liabilities held at end of period |
|
$ |
3 |
|
|
$ |
- |
|
Quantitative information about unobservable inputs used in Level 3 fair value measurements is presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Valuation Technique |
|
|
Unobservable Input |
|
As at
June 30, 2015 |
|
|
As at
December 31, 2014 |
|
Risk Management - Power |
|
|
Discounted Cash Flow |
|
|
Forward prices ($/Megawatt Hour) |
|
$ |
44.50 - $56.96 |
|
|
$ |
40.70 - $48.50 |
|
A 10 percent increase or decrease in estimated forward power prices would cause a corresponding $6 million ($5 million
as at December 31, 2014) increase or decrease to net risk management assets and liabilities.
|
|
|
|
|
Notes to Condensed Consolidated Financial Statements
Prepared in accordance with U.S. GAAP in US$ |
|
|
|
Q2 Report | For the period ended June 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 June 30,
2015 |
|
|
As at December 31, 2014 |
|
|
|
|
Risk Management Assets |
|
|
|
|
|
|
|
|
Current |
|
$ |
330 |
|
|
$ |
707 |
|
Long-term |
|
|
11 |
|
|
|
65 |
|
|
|
|
341 |
|
|
|
772 |
|
|
|
|
Risk Management Liabilities |
|
|
|
|
|
|
|
|
Current |
|
|
26 |
|
|
|
20 |
|
Long-term |
|
|
15 |
|
|
|
7 |
|
|
|
|
41 |
|
|
|
27 |
|
Net Risk Management Assets |
|
$ |
300 |
|
|
$ |
745 |
|
Commodity Price Positions as at June 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 |
|
|
$ |
255 |
|
|
|
|
|
|
Basis Contracts (1) |
|
|
|
|
|
2015-2018 |
|
|
|
|
|
|
54 |
|
|
|
|
|
|
Other Financial Positions |
|
|
|
|
|
|
|
|
|
|
|
|
- |
|
|
|
|
|
|
Natural Gas Fair Value Position |
|
|
|
|
|
|
|
|
|
|
|
|
309 |
|
|
|
|
|
|
Crude Oil Contracts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed Price Contracts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WTI Fixed Price |
|
|
59.4 Mbbls/d |
|
|
2015 |
|
|
61.96 US$/bbl |
|
|
|
17 |
|
WTI Fixed Price |
|
|
38.0 Mbbls/d |
|
|
2016 |
|
|
62.83 US$/bbl |
|
|
|
11 |
|
|
|
|
|
|
Basis Contracts (2) |
|
|
|
|
|
2015-2016 |
|
|
|
|
|
|
(27 |
) |
|
|
|
|
|
Crude Oil Fair Value Position |
|
|
|
|
|
|
|
|
|
|
|
|
1 |
|
|
|
|
|
|
Power Purchase Contracts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Position |
|
|
|
|
|
|
|
|
|
|
|
|
(10 |
) |
|
|
|
|
|
Total Fair Value Position |
|
|
|
|
|
|
|
|
|
|
|
$ |
300 |
|
|
(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) |
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$ |
|
Q2 Report | For the period ended June 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
June 30, |
|
|
Six Months Ended
June 30, |
|
|
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
Revenues, Net of Royalties |
|
$ |
164 |
|
|
$ |
(99 |
) |
|
$ |
409 |
|
|
$ |
(239 |
) |
Transportation and Processing |
|
|
(3 |
) |
|
|
(3 |
) |
|
|
(8 |
) |
|
|
(4 |
) |
Gain (Loss) on Risk Management |
|
$ |
161 |
|
|
$ |
(102 |
) |
|
$ |
401 |
|
|
$ |
(243 |
) |
|
|
|
|
Unrealized Gain (Loss) |
|
|
|
Three Months Ended
June 30, |
|
|
Six Months Ended
June 30, |
|
|
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
|
|
|
|
|
|
Revenues, Net of Royalties |
|
$ |
(293 |
) |
|
$ |
7 |
|
|
$ |
(421 |
) |
|
$ |
(277 |
) |
Transportation and Processing |
|
|
15 |
|
|
|
2 |
|
|
|
7 |
|
|
|
1 |
|
Gain (Loss) on Risk Management |
|
$ |
(278 |
) |
|
$ |
9 |
|
|
$ |
(414 |
) |
|
$ |
(276 |
) |
Reconciliation of Unrealized Risk Management Positions from January 1 to June 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 |
|
|
(13 |
) |
|
$ |
(13 |
) |
|
$ |
(519 |
) |
Settlement of Athlon Crude Oil Contracts from Business Combination |
|
|
(31 |
) |
|
|
|
|
|
|
|
|
Fair Value of Contracts Realized During the Period |
|
|
(401 |
) |
|
|
(401 |
) |
|
|
243 |
|
Fair Value of Contracts, End of Period |
|
$ |
300 |
|
|
$ |
414 |
) |
|
$ |
(276 |
) |
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 swaps and options. 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 against crude oil commodity price risk including widening price differentials between North American and world prices,
the Company has entered into fixed price contracts and basis swaps.
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$ |
|
|
|
Q2 Report | For the period ended June 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 six months ended June 30 as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2015 |
|
|
2014 |
|
|
|
10% Price Increase |
|
|
10% Price Decrease |
|
|
10% Price Increase |
|
|
10% Price Decrease |
|
|
|
|
|
|
Natural Gas Price |
|
$ |
(39) |
|
|
$ |
39 |
|
|
$ |
(300) |
|
|
$ |
300 |
|
Crude Oil Price |
|
|
(150) |
|
|
|
150 |
|
|
|
(48) |
|
|
|
48 |
|
Power Price |
|
|
6 |
|
|
|
(6) |
|
|
|
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 June 30, 2015, the Company had
no significant collateral balances posted or received and there were no credit derivatives in place.
As at June 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 June 30, 2015, approximately 88 percent (94 percent as at December 31, 2014) of Encanas accounts receivable and financial derivative credit exposures
were with investment grade counterparties.
As at June 30, 2015, Encana had four 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 June 30, 2015, these counterparties accounted for 20
percent, 18 percent, 16 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 June 30, 2015, the Company had committed revolving bank credit facilities totaling $3.8 billion which include C$3.5 billion ($2.8 billion) on a revolving bank credit facility for Encana and $1.0
billion on a revolving bank credit facility for a U.S. subsidiary, the latter of which remains unused. Of the C$3.5 billion ($2.8 billion) revolving bank credit facility, $1.4 billion was fully supporting the U.S. Commercial Paper Program and $1.4
billion remained unused.
Encana also has accessible capacity under a shelf prospectus for up to $4.9 billion, or the equivalent in foreign
currencies, the availability of which is dependent on market conditions, to issue debt and/or equity securities in Canada and/or the U.S. The shelf prospectus expires in July 2016.
The Company believes it has sufficient funding through the use of these facilities to meet foreseeable borrowing requirements.
|
|
|
|
|
|
|
Notes to Condensed Consolidated Financial Statements
Prepared in accordance with U.S. GAAP in US$ |
|
Q2 Report | For the period ended June 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 |
|
$ |
1,744 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
1,744 |
|
Risk Management Liabilities |
|
|
26 |
|
|
|
15 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
41 |
|
Long-Term Debt (1) |
|
|
306 |
|
|
|
612 |
|
|
|
2,466 |
|
|
|
1,599 |
|
|
|
6,271 |
|
|
|
11,254 |
|
(1) |
Principal and interest. |
Included in
Encanas long-term debt obligations of $11,254 million at June 30, 2015 are $1,397 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 June 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 June 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 $50 million change in foreign exchange (gain) loss as at June 30, 2015 (2014 - $46 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 June 30, 2015.
As at June 30, 2015, the Company had floating rate debt of $1,397 million. Accordingly, the sensitivity in net earnings for each one percent change
in interest rates on floating rate debt was $10 million (2014 - nil).
|
|
|
|
|
Notes to Condensed Consolidated Financial Statements
Prepared in accordance with U.S. GAAP in US$ |
|
|
|
Q2 Report | For the period ended June 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 June 30, 2015:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected Future Payments |
|
(undiscounted) |
|
2015 |
|
|
2016 |
|
|
2017 |
|
|
2018 |
|
|
2019 |
|
|
Thereafter |
|
|
Total |
|
|
|
|
|
|
|
|
|
Transportation and Processing |
|
$ |
427 |
|
|
$ |
817 |
|
|
$ |
800 |
|
|
$ |
816 |
|
|
$ |
697 |
|
|
$ |
3,253 |
|
|
$ |
6,810 |
|
Drilling and Field Services |
|
|
125 |
|
|
|
136 |
|
|
|
102 |
|
|
|
51 |
|
|
|
15 |
|
|
|
16 |
|
|
|
445 |
|
Operating Leases |
|
|
18 |
|
|
|
30 |
|
|
|
25 |
|
|
|
24 |
|
|
|
11 |
|
|
|
24 |
|
|
|
132 |
|
Total |
|
$ |
570 |
|
|
$ |
983 |
|
|
$ |
927 |
|
|
$ |
891 |
|
|
$ |
723 |
|
|
$ |
3,293 |
|
|
$ |
7,387 |
|
Included within transportation and processing in the table above are certain commitments associated with midstream
service agreements with VMLP as described in Note 16.
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.
|
|
|
|
|
|
|
Notes to Condensed Consolidated Financial Statements
Prepared in accordance with U.S. GAAP in US$ |
|
Q2 Report | For the period ended June 30,
2015 |
|
Supplemental Financial Information (unaudited) |
Financial Results
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2015 |
|
|
2014 |
|
($ millions, except per share amounts) |
|
Year-to- date |
|
|
Q2 |
|
|
Q1 |
|
|
Year |
|
|
Q4 |
|
|
Q3 |
|
|
Q2 Year- to-date |
|
|
Q2 |
|
|
Q1 |
|
|
|
|
|
|
|
|
|
|
|
Cash Flow (1) |
|
|
676 |
|
|
|
181 |
|
|
|
495 |
|
|
|
2,934 |
|
|
|
377 |
|
|
|
807 |
|
|
|
1,750 |
|
|
|
656 |
|
|
|
1,094 |
|
|
|
|
|
|
|
|
|
|
|
Per share - Diluted (4) |
|
|
0.85 |
|
|
|
0.22 |
|
|
|
0.65 |
|
|
|
3.96 |
|
|
|
0.51 |
|
|
|
1.09 |
|
|
|
2.36 |
|
|
|
0.89 |
|
|
|
1.48 |
|
|
|
|
|
|
|
|
|
|
|
Operating Earnings (Loss) (2,3) |
|
|
(148 |
) |
|
|
(167 |
) |
|
|
19 |
|
|
|
1,002 |
|
|
|
35 |
|
|
|
281 |
|
|
|
686 |
|
|
|
171 |
|
|
|
515 |
|
|
|
|
|
|
|
|
|
|
|
Per share - Diluted (4) |
|
|
(0.19 |
) |
|
|
(0.20 |
) |
|
|
0.03 |
|
|
|
1.35 |
|
|
|
0.05 |
|
|
|
0.38 |
|
|
|
0.93 |
|
|
|
0.23 |
|
|
|
0.70 |
|
|
|
|
|
|
|
|
|
|
|
Net Earnings (Loss) Attributable to Common Shareholders |
|
|
(3,317 |
) |
|
|
(1,610 |
) |
|
|
(1,707 |
) |
|
|
3,392 |
|
|
|
198 |
|
|
|
2,807 |
|
|
|
387 |
|
|
|
271 |
|
|
|
116 |
|
|
|
|
|
|
|
|
|
|
|
Per share - Diluted (4) |
|
|
(4.15 |
) |
|
|
(1.91 |
) |
|
|
(2.25 |
) |
|
|
4.58 |
|
|
|
0.27 |
|
|
|
3.79 |
|
|
|
0.52 |
|
|
|
0.37 |
|
|
|
0.16 |
|
|
|
|
|
|
|
|
|
|
|
Effective Tax Rate using Canadian Statutory Rate |
|
|
26.4% |
|
|
|
|
|
|
|
|
|
|
|
25.7% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign Exchange Rates (US$ per C$1)
Average |
|
|
0.810 |
|
|
|
0.813 |
|
|
|
0.806 |
|
|
|
0.905 |
|
|
|
0.881 |
|
|
|
0.918 |
|
|
|
0.912 |
|
|
|
0.917 |
|
|
|
0.906 |
|
Period end |
|
|
0.802 |
|
|
|
0.802 |
|
|
|
0.789 |
|
|
|
0.862 |
|
|
|
0.862 |
|
|
|
0.892 |
|
|
|
0.937 |
|
|
|
0.937 |
|
|
|
0.905 |
|
|
|
|
|
|
|
|
|
|
|
Cash Flow Summary |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash From (Used in) Operating Activities |
|
|
780 |
|
|
|
298 |
|
|
|
482 |
|
|
|
2,667 |
|
|
|
261 |
|
|
|
696 |
|
|
|
1,710 |
|
|
|
767 |
|
|
|
943 |
|
Deduct (Add back): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net change in other assets and liabilities |
|
|
- |
|
|
|
7 |
|
|
|
(7 |
) |
|
|
(43 |
) |
|
|
(15 |
) |
|
|
(11 |
) |
|
|
(17 |
) |
|
|
(8 |
) |
|
|
(9 |
) |
Net change in non-cash working capital |
|
|
104 |
|
|
|
110 |
|
|
|
(6 |
) |
|
|
(9 |
) |
|
|
(141 |
) |
|
|
155 |
|
|
|
(23 |
) |
|
|
119 |
|
|
|
(142 |
) |
Cash tax on sale of assets |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(215 |
) |
|
|
40 |
|
|
|
(255 |
) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
Cash Flow (1) |
|
|
676 |
|
|
|
181 |
|
|
|
495 |
|
|
|
2,934 |
|
|
|
377 |
|
|
|
807 |
|
|
|
1,750 |
|
|
|
656 |
|
|
|
1,094 |
|
|
|
|
|
|
|
|
|
|
|
Operating Earnings Summary |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Earnings (Loss) Attributable to Common Shareholders |
|
|
(3,317 |
) |
|
|
(1,610 |
) |
|
|
(1,707 |
) |
|
|
3,392 |
|
|
|
198 |
|
|
|
2,807 |
|
|
|
387 |
|
|
|
271 |
|
|
|
116 |
|
After-tax (addition) deduction: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized hedging gain (loss) |
|
|
(285 |
) |
|
|
(187 |
) |
|
|
(98 |
) |
|
|
306 |
|
|
|
341 |
|
|
|
160 |
|
|
|
(195 |
) |
|
|
8 |
|
|
|
(203 |
) |
Impairments |
|
|
(2,550 |
) |
|
|
(1,328 |
) |
|
|
(1,222 |
) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Restructuring charges (3) |
|
|
(20 |
) |
|
|
(10 |
) |
|
|
(10 |
) |
|
|
(24 |
) |
|
|
(4 |
) |
|
|
(5 |
) |
|
|
(15 |
) |
|
|
(5 |
) |
|
|
(10 |
) |
Non-operating foreign exchange gain (loss) |
|
|
(394 |
) |
|
|
114 |
|
|
|
(508 |
) |
|
|
(407 |
) |
|
|
(151 |
) |
|
|
(218 |
) |
|
|
(38 |
) |
|
|
156 |
|
|
|
(194 |
) |
Gain (loss) on divestitures |
|
|
11 |
|
|
|
1 |
|
|
|
10 |
|
|
|
2,523 |
|
|
|
(11 |
) |
|
|
2,399 |
|
|
|
135 |
|
|
|
135 |
|
|
|
- |
|
Income tax adjustments |
|
|
69 |
|
|
|
(33 |
) |
|
|
102 |
|
|
|
(8 |
) |
|
|
(12 |
) |
|
|
190 |
|
|
|
(186 |
) |
|
|
(194 |
) |
|
|
8 |
|
Operating Earnings (Loss) (2,3) |
|
|
(148 |
) |
|
|
(167 |
) |
|
|
19 |
|
|
|
1,002 |
|
|
|
35 |
|
|
|
281 |
|
|
|
686 |
|
|
|
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 |
|
|
Q2 |
|
|
Q1 |
|
|
Year |
|
|
Q4 |
|
|
Q3 |
|
|
Q2 Year- to-date |
|
|
Q2 |
|
|
Q1 |
|
|
|
|
|
|
|
|
|
|
|
Weighted Average Common Shares Outstanding |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
799.5 |
|
|
|
841.2 |
|
|
|
757.8 |
|
|
|
741.0 |
|
|
|
741.1 |
|
|
|
741.1 |
|
|
|
741.0 |
|
|
|
741.0 |
|
|
|
741.0 |
|
Diluted |
|
|
799.5 |
|
|
|
841.2 |
|
|
|
757.8 |
|
|
|
741.0 |
|
|
|
741.1 |
|
|
|
741.1 |
|
|
|
741.0 |
|
|
|
741.0 |
|
|
|
741.0 |
|
|
|
|
|
|
Supplemental Information
Prepared in US$ |
|
|
|
Q2 Report | For the period ended June 30, 2015
|
|
Supplemental Financial & Operating Information (unaudited) |
Financial Metrics
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2015 |
|
|
|
|
|
|
|
|
2014 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year-to- date |
|
|
|
|
|
|
|
|
Year |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Debt to Debt Adjusted Cash Flow |
|
|
2.5x |
|
|
|
|
|
|
|
|
|
|
|
2.1x |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Debt to Adjusted Capitalization |
|
|
28% |
|
|
|
|
|
|
|
|
|
|
|
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 |
|
|
Q2 |
|
|
Q1 |
|
|
Year |
|
|
Q4 |
|
|
Q3 |
|
|
Q2 Year- to-date |
|
|
Q2 |
|
|
Q1 |
|
|
|
|
|
|
|
|
|
|
|
Capital Investment |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
|
265 |
|
|
|
114 |
|
|
|
151 |
|
|
|
1,226 |
|
|
|
302 |
|
|
|
293 |
|
|
|
631 |
|
|
|
350 |
|
|
|
281 |
|
USA Operations |
|
|
1,211 |
|
|
|
628 |
|
|
|
583 |
|
|
|
1,285 |
|
|
|
548 |
|
|
|
305 |
|
|
|
432 |
|
|
|
206 |
|
|
|
226 |
|
Market Optimization |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(2 |
) |
|
|
2 |
|
|
|
1 |
|
|
|
1 |
|
Corporate & Other |
|
|
3 |
|
|
|
1 |
|
|
|
2 |
|
|
|
15 |
|
|
|
7 |
|
|
|
2 |
|
|
|
6 |
|
|
|
3 |
|
|
|
3 |
|
|
|
|
|
|
|
|
|
|
|
Capital Investment |
|
|
1,479 |
|
|
|
743 |
|
|
|
736 |
|
|
|
2,526 |
|
|
|
857 |
|
|
|
598 |
|
|
|
1,071 |
|
|
|
560 |
|
|
|
511 |
|
|
|
|
|
|
|
|
|
|
|
Net Acquisitions & (Divestitures) |
|
|
(978) |
|
|
|
(140 |
) |
|
|
(838 |
) |
|
|
(1,329 |
) |
|
|
50 |
|
|
|
(2,007 |
) |
|
|
628 |
|
|
|
652 |
|
|
|
(24 |
) |
|
|
|
|
|
|
|
|
|
|
Net Capital Investment |
|
|
501 |
|
|
|
603 |
|
|
|
(102 |
) |
|
|
1,197 |
|
|
|
907 |
|
|
|
(1,409 |
) |
|
|
1,699 |
|
|
|
1,212 |
|
|
|
487 |
|
Capital Investment
|
|
|
|
2015 |
|
|
2014 |
|
($ millions) |
|
Year-to- date |
|
|
Q2 |
|
|
Q1 |
|
|
Year |
|
|
Q4 |
|
|
Q3 |
|
|
Q2 Year- to-date |
|
|
Q2 |
|
|
Q1 |
|
|
|
|
|
|
|
|
|
|
|
Capital Investment |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Montney (1) |
|
|
127 |
|
|
|
48 |
|
|
|
79 |
|
|
|
781 |
|
|
|
159 |
|
|
|
204 |
|
|
|
418 |
|
|
|
210 |
|
|
|
208 |
|
Duvernay |
|
|
127 |
|
|
|
57 |
|
|
|
70 |
|
|
|
328 |
|
|
|
118 |
|
|
|
58 |
|
|
|
152 |
|
|
|
81 |
|
|
|
71 |
|
Eagle Ford |
|
|
372 |
|
|
|
175 |
|
|
|
197 |
|
|
|
274 |
|
|
|
149 |
|
|
|
113 |
|
|
|
12 |
|
|
|
12 |
|
|
|
- |
|
Permian |
|
|
542 |
|
|
|
325 |
|
|
|
217 |
|
|
|
117 |
|
|
|
117 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
DJ Basin |
|
|
144 |
|
|
|
56 |
|
|
|
88 |
|
|
|
277 |
|
|
|
81 |
|
|
|
68 |
|
|
|
128 |
|
|
|
69 |
|
|
|
59 |
|
San Juan |
|
|
59 |
|
|
|
23 |
|
|
|
36 |
|
|
|
287 |
|
|
|
96 |
|
|
|
89 |
|
|
|
102 |
|
|
|
50 |
|
|
|
52 |
|
|
|
|
1,371 |
|
|
|
684 |
|
|
|
687 |
|
|
|
2,064 |
|
|
|
720 |
|
|
|
532 |
|
|
|
812 |
|
|
|
422 |
|
|
|
390 |
|
|
|
|
|
|
|
|
|
|
|
Other Upstream Operations (1, 2) |
|
|
105 |
|
|
|
58 |
|
|
|
47 |
|
|
|
447 |
|
|
|
130 |
|
|
|
66 |
|
|
|
251 |
|
|
|
134 |
|
|
|
117 |
|
Market Optimization |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(2 |
) |
|
|
2 |
|
|
|
1 |
|
|
|
1 |
|
Corporate & Other |
|
|
3 |
|
|
|
1 |
|
|
|
2 |
|
|
|
15 |
|
|
|
7 |
|
|
|
2 |
|
|
|
6 |
|
|
|
3 |
|
|
|
3 |
|
|
|
|
|
|
|
|
|
|
|
Capital Investment |
|
|
1,479 |
|
|
|
743 |
|
|
|
736 |
|
|
|
2,526 |
|
|
|
857 |
|
|
|
598 |
|
|
|
1,071 |
|
|
|
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). 2015 year-to-date capital investment for the TMS was $42 million (2014 year-to-date - $47 million).
|
|
|
|
|
|
|
|
Supplemental Information Prepared in US$ |
|
Q2 Report | For the period ended June 30,
2015 |
|
Supplemental Financial & Operating Information (unaudited) |
Production Volumes - After Royalties
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2015 |
|
|
2014 |
|
(average) |
|
Year-to- date |
|
|
Q2 |
|
|
Q1 |
|
|
Year |
|
|
Q4 |
|
|
Q3 |
|
|
Q2 Year- to-date |
|
|
Q2 |
|
|
Q1 |
|
|
|
|
|
|
|
|
|
|
|
Natural Gas (MMcf/d) |
|
|
1,712 |
|
|
|
1,568 |
|
|
|
1,857 |
|
|
|
2,350 |
|
|
|
1,861 |
|
|
|
2,199 |
|
|
|
2,675 |
|
|
|
2,541 |
|
|
|
2,809 |
|
|
|
|
|
|
|
|
|
|
|
Oil (Mbbls/d) |
|
|
82.7 |
|
|
|
86.2 |
|
|
|
79.2 |
|
|
|
49.4 |
|
|
|
68.8 |
|
|
|
62.1 |
|
|
|
33.1 |
|
|
|
34.2 |
|
|
|
32.1 |
|
NGLs (Mbbls/d) |
|
|
41.3 |
|
|
|
41.1 |
|
|
|
41.5 |
|
|
|
37.4 |
|
|
|
37.6 |
|
|
|
41.9 |
|
|
|
34.9 |
|
|
|
34.0 |
|
|
|
35.8 |
|
Oil & NGLs (Mbbls/d) |
|
|
124.0 |
|
|
|
127.3 |
|
|
|
120.7 |
|
|
|
86.8 |
|
|
|
106.4 |
|
|
|
104.0 |
|
|
|
68.0 |
|
|
|
68.2 |
|
|
|
67.9 |
|
|
|
|
|
|
|
|
|
|
|
Total (MBOE/d) |
|
|
409.3 |
|
|
|
388.7 |
|
|
|
430.1 |
|
|
|
478.5 |
|
|
|
416.7 |
|
|
|
470.6 |
|
|
|
513.8 |
|
|
|
491.8 |
|
|
|
536.1 |
|
Production Volumes - After Royalties
|
|
|
|
2015 |
|
|
2014 |
|
(average) |
|
Year-to- date |
|
|
Q2 |
|
|
Q1 |
|
|
Year |
|
|
Q4 |
|
|
Q3 |
|
|
Q2 Year- to-date |
|
|
Q2 |
|
|
Q1 |
|
|
|
|
|
|
|
|
|
|
|
Natural Gas (MMcf/d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
|
1,004 |
|
|
|
881 |
|
|
|
1,128 |
|
|
|
1,378 |
|
|
|
1,111 |
|
|
|
1,374 |
|
|
|
1,516 |
|
|
|
1,463 |
|
|
|
1,568 |
|
USA Operations |
|
|
708 |
|
|
|
687 |
|
|
|
729 |
|
|
|
972 |
|
|
|
750 |
|
|
|
825 |
|
|
|
1,159 |
|
|
|
1,078 |
|
|
|
1,241 |
|
|
|
|
1,712 |
|
|
|
1,568 |
|
|
|
1,857 |
|
|
|
2,350 |
|
|
|
1,861 |
|
|
|
2,199 |
|
|
|
2,675 |
|
|
|
2,541 |
|
|
|
2,809 |
|
|
|
|
|
|
|
|
|
|
|
Oil (Mbbls/d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
|
6.5 |
|
|
|
6.5 |
|
|
|
6.6 |
|
|
|
13.6 |
|
|
|
9.4 |
|
|
|
14.7 |
|
|
|
15.1 |
|
|
|
13.9 |
|
|
|
16.4 |
|
USA Operations |
|
|
76.2 |
|
|
|
79.7 |
|
|
|
72.6 |
|
|
|
35.8 |
|
|
|
59.4 |
|
|
|
47.4 |
|
|
|
18.0 |
|
|
|
20.3 |
|
|
|
15.7 |
|
|
|
|
82.7 |
|
|
|
86.2 |
|
|
|
79.2 |
|
|
|
49.4 |
|
|
|
68.8 |
|
|
|
62.1 |
|
|
|
33.1 |
|
|
|
34.2 |
|
|
|
32.1 |
|
|
|
|
|
|
|
|
|
|
|
NGLs (Mbbls/d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
|
20.5 |
|
|
|
19.8 |
|
|
|
21.2 |
|
|
|
23.6 |
|
|
|
18.8 |
|
|
|
27.6 |
|
|
|
24.1 |
|
|
|
23.5 |
|
|
|
24.6 |
|
USA Operations |
|
|
20.8 |
|
|
|
21.3 |
|
|
|
20.3 |
|
|
|
13.8 |
|
|
|
18.8 |
|
|
|
14.3 |
|
|
|
10.8 |
|
|
|
10.5 |
|
|
|
11.2 |
|
|
|
|
41.3 |
|
|
|
41.1 |
|
|
|
41.5 |
|
|
|
37.4 |
|
|
|
37.6 |
|
|
|
41.9 |
|
|
|
34.9 |
|
|
|
34.0 |
|
|
|
35.8 |
|
|
|
|
|
|
|
|
|
|
|
Oil & NGLs (Mbbls/d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
|
27.0 |
|
|
|
26.3 |
|
|
|
27.8 |
|
|
|
37.2 |
|
|
|
28.2 |
|
|
|
42.3 |
|
|
|
39.2 |
|
|
|
37.4 |
|
|
|
41.0 |
|
USA Operations |
|
|
97.0 |
|
|
|
101.0 |
|
|
|
92.9 |
|
|
|
49.6 |
|
|
|
78.2 |
|
|
|
61.7 |
|
|
|
28.8 |
|
|
|
30.8 |
|
|
|
26.9 |
|
|
|
|
124.0 |
|
|
|
127.3 |
|
|
|
120.7 |
|
|
|
86.8 |
|
|
|
106.4 |
|
|
|
104.0 |
|
|
|
68.0 |
|
|
|
68.2 |
|
|
|
67.9 |
|
|
|
|
|
|
|
|
|
|
|
Total (MBOE/d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
|
194.4 |
|
|
|
173.2 |
|
|
|
215.8 |
|
|
|
266.9 |
|
|
|
213.4 |
|
|
|
271.4 |
|
|
|
291.8 |
|
|
|
281.4 |
|
|
|
302.4 |
|
USA Operations |
|
|
214.9 |
|
|
|
215.5 |
|
|
|
214.3 |
|
|
|
211.6 |
|
|
|
203.3 |
|
|
|
199.2 |
|
|
|
222.0 |
|
|
|
210.4 |
|
|
|
233.7 |
|
|
|
|
409.3 |
|
|
|
388.7 |
|
|
|
430.1 |
|
|
|
478.5 |
|
|
|
416.7 |
|
|
|
470.6 |
|
|
|
513.8 |
|
|
|
491.8 |
|
|
|
536.1 |
|
Oil & NGLs Production Volumes - After Royalties
|
|
|
|
2015 |
|
|
|
|
|
2014 |
|
|
|
|
|
|
|
|
|
|
|
|
|
(average Mbbls/d) |
|
Year-to- date |
|
|
% of Total |
|
|
|
|
|
Year |
|
|
% of Total |
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
|
82.7 |
|
|
|
67 |
|
|
|
|
|
|
|
49.4 |
|
|
|
57 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Plant Condensate |
|
|
14.0 |
|
|
|
11 |
|
|
|
|
|
|
|
12.0 |
|
|
|
14 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Butane |
|
|
6.7 |
|
|
|
5 |
|
|
|
|
|
|
|
6.8 |
|
|
|
8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Propane |
|
|
11.1 |
|
|
|
9 |
|
|
|
|
|
|
|
10.2 |
|
|
|
11 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ethane |
|
|
9.5 |
|
|
|
8 |
|
|
|
|
|
|
|
8.4 |
|
|
|
10 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
124.0 |
|
|
|
100 |
|
|
|
|
|
|
|
86.8 |
|
|
|
100 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental Information
Prepared in US$ |
|
|
|
Q2 Report | For the period ended June 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 |
|
|
Q2 |
|
|
Q1 |
|
|
Year |
|
|
Q4 |
|
|
Q3 |
|
|
Q2 Year- to-date |
|
|
Q2 |
|
|
Q1 |
|
Natural Gas - Canadian Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues, Net of Royalties, excluding Hedging |
|
|
589 |
|
|
|
193 |
|
|
|
396 |
|
|
|
2,468 |
|
|
|
402 |
|
|
|
480 |
|
|
|
1,586 |
|
|
|
569 |
|
|
|
1,017 |
|
Realized Financial Hedging Gain (Loss) |
|
|
260 |
|
|
|
106 |
|
|
|
154 |
|
|
|
(74 |
) |
|
|
25 |
|
|
|
20 |
|
|
|
(119 |
) |
|
|
(44 |
) |
|
|
(75 |
) |
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and mineral taxes |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
5 |
|
|
|
2 |
|
|
|
1 |
|
|
|
2 |
|
|
|
- |
|
|
|
2 |
|
Transportation and processing |
|
|
321 |
|
|
|
158 |
|
|
|
163 |
|
|
|
773 |
|
|
|
177 |
|
|
|
186 |
|
|
|
410 |
|
|
|
209 |
|
|
|
201 |
|
Operating |
|
|
76 |
|
|
|
40 |
|
|
|
36 |
|
|
|
279 |
|
|
|
57 |
|
|
|
66 |
|
|
|
156 |
|
|
|
72 |
|
|
|
84 |
|
Operating Cash Flow |
|
|
452 |
|
|
|
101 |
|
|
|
351 |
|
|
|
1,337 |
|
|
|
191 |
|
|
|
247 |
|
|
|
899 |
|
|
|
244 |
|
|
|
655 |
|
Natural Gas - USA Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues, Net of Royalties, excluding Hedging |
|
|
341 |
|
|
|
146 |
|
|
|
195 |
|
|
|
1,640 |
|
|
|
274 |
|
|
|
307 |
|
|
|
1,059 |
|
|
|
463 |
|
|
|
596 |
|
Realized Financial Hedging Gain (Loss) |
|
|
112 |
|
|
|
58 |
|
|
|
54 |
|
|
|
(85 |
) |
|
|
13 |
|
|
|
10 |
|
|
|
(108 |
) |
|
|
(43 |
) |
|
|
(65 |
) |
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and mineral taxes |
|
|
9 |
|
|
|
5 |
|
|
|
4 |
|
|
|
44 |
|
|
|
11 |
|
|
|
(10 |
) |
|
|
43 |
|
|
|
14 |
|
|
|
29 |
|
Transportation and processing |
|
|
293 |
|
|
|
142 |
|
|
|
151 |
|
|
|
651 |
|
|
|
149 |
|
|
|
162 |
|
|
|
340 |
|
|
|
177 |
|
|
|
163 |
|
Operating |
|
|
95 |
|
|
|
46 |
|
|
|
49 |
|
|
|
235 |
|
|
|
52 |
|
|
|
50 |
|
|
|
133 |
|
|
|
65 |
|
|
|
68 |
|
Operating Cash Flow |
|
|
56 |
|
|
|
11 |
|
|
|
45 |
|
|
|
625 |
|
|
|
75 |
|
|
|
115 |
|
|
|
435 |
|
|
|
164 |
|
|
|
271 |
|
Natural Gas - Total Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues, Net of Royalties, excluding Hedging |
|
|
930 |
|
|
|
339 |
|
|
|
591 |
|
|
|
4,108 |
|
|
|
676 |
|
|
|
787 |
|
|
|
2,645 |
|
|
|
1,032 |
|
|
|
1,613 |
|
Realized Financial Hedging Gain (Loss) |
|
|
372 |
|
|
|
164 |
|
|
|
208 |
|
|
|
(159 |
) |
|
|
38 |
|
|
|
30 |
|
|
|
(227 |
) |
|
|
(87 |
) |
|
|
(140 |
) |
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and mineral taxes |
|
|
9 |
|
|
|
5 |
|
|
|
4 |
|
|
|
49 |
|
|
|
13 |
|
|
|
(9 |
) |
|
|
45 |
|
|
|
14 |
|
|
|
31 |
|
Transportation and processing |
|
|
614 |
|
|
|
300 |
|
|
|
314 |
|
|
|
1,424 |
|
|
|
326 |
|
|
|
348 |
|
|
|
750 |
|
|
|
386 |
|
|
|
364 |
|
Operating |
|
|
171 |
|
|
|
86 |
|
|
|
85 |
|
|
|
514 |
|
|
|
109 |
|
|
|
116 |
|
|
|
289 |
|
|
|
137 |
|
|
|
152 |
|
Operating Cash Flow |
|
|
508 |
|
|
|
112 |
|
|
|
396 |
|
|
|
1,962 |
|
|
|
266 |
|
|
|
362 |
|
|
|
1,334 |
|
|
|
408 |
|
|
|
926 |
|
Oil & NGLs - Canadian Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues, Net of Royalties, excluding Hedging |
|
|
168 |
|
|
|
91 |
|
|
|
77 |
|
|
|
872 |
|
|
|
149 |
|
|
|
251 |
|
|
|
472 |
|
|
|
227 |
|
|
|
245 |
|
Realized Financial Hedging Gain (Loss) |
|
|
(3 |
) |
|
|
(5 |
) |
|
|
2 |
|
|
|
18 |
|
|
|
24 |
|
|
|
(1 |
) |
|
|
(5 |
) |
|
|
(5 |
) |
|
|
- |
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and mineral taxes |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
10 |
|
|
|
- |
|
|
|
3 |
|
|
|
7 |
|
|
|
4 |
|
|
|
3 |
|
Transportation and processing |
|
|
27 |
|
|
|
13 |
|
|
|
14 |
|
|
|
62 |
|
|
|
16 |
|
|
|
16 |
|
|
|
30 |
|
|
|
16 |
|
|
|
14 |
|
Operating |
|
|
11 |
|
|
|
5 |
|
|
|
6 |
|
|
|
28 |
|
|
|
10 |
|
|
|
8 |
|
|
|
10 |
|
|
|
4 |
|
|
|
6 |
|
Operating Cash Flow |
|
|
127 |
|
|
|
68 |
|
|
|
59 |
|
|
|
790 |
|
|
|
147 |
|
|
|
223 |
|
|
|
420 |
|
|
|
198 |
|
|
|
222 |
|
Oil & NGLs - USA Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues, Net of Royalties, excluding Hedging |
|
|
709 |
|
|
|
414 |
|
|
|
295 |
|
|
|
1,258 |
|
|
|
412 |
|
|
|
452 |
|
|
|
394 |
|
|
|
215 |
|
|
|
179 |
|
Realized Financial Hedging Gain (Loss) |
|
|
43 |
|
|
|
5 |
|
|
|
38 |
|
|
|
60 |
|
|
|
65 |
|
|
|
1 |
|
|
|
(6 |
) |
|
|
(6 |
) |
|
|
- |
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and mineral taxes |
|
|
36 |
|
|
|
21 |
|
|
|
15 |
|
|
|
74 |
|
|
|
23 |
|
|
|
23 |
|
|
|
28 |
|
|
|
15 |
|
|
|
13 |
|
Transportation and processing |
|
|
6 |
|
|
|
2 |
|
|
|
4 |
|
|
|
7 |
|
|
|
3 |
|
|
|
4 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Operating |
|
|
179 |
|
|
|
104 |
|
|
|
75 |
|
|
|
115 |
|
|
|
51 |
|
|
|
44 |
|
|
|
20 |
|
|
|
12 |
|
|
|
8 |
|
Operating Cash Flow |
|
|
531 |
|
|
|
292 |
|
|
|
239 |
|
|
|
1,122 |
|
|
|
400 |
|
|
|
382 |
|
|
|
340 |
|
|
|
182 |
|
|
|
158 |
|
Oil & NGLs - Total Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues, Net of Royalties, excluding Hedging |
|
|
877 |
|
|
|
505 |
|
|
|
372 |
|
|
|
2,130 |
|
|
|
561 |
|
|
|
703 |
|
|
|
866 |
|
|
|
442 |
|
|
|
424 |
|
Realized Financial Hedging Gain (Loss) |
|
|
40 |
|
|
|
- |
|
|
|
40 |
|
|
|
78 |
|
|
|
89 |
|
|
|
- |
|
|
|
(11 |
) |
|
|
(11 |
) |
|
|
- |
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and mineral taxes |
|
|
36 |
|
|
|
21 |
|
|
|
15 |
|
|
|
84 |
|
|
|
23 |
|
|
|
26 |
|
|
|
35 |
|
|
|
19 |
|
|
|
16 |
|
Transportation and processing |
|
|
33 |
|
|
|
15 |
|
|
|
18 |
|
|
|
69 |
|
|
|
19 |
|
|
|
20 |
|
|
|
30 |
|
|
|
16 |
|
|
|
14 |
|
Operating |
|
|
190 |
|
|
|
109 |
|
|
|
81 |
|
|
|
143 |
|
|
|
61 |
|
|
|
52 |
|
|
|
30 |
|
|
|
16 |
|
|
|
14 |
|
Operating Cash Flow |
|
|
658 |
|
|
|
360 |
|
|
|
298 |
|
|
|
1,912 |
|
|
|
547 |
|
|
|
605 |
|
|
|
760 |
|
|
|
380 |
|
|
|
380 |
|
|
|
|
|
|
|
|
Supplemental Information Prepared in US$ |
|
Q2 Report | For the period ended June 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 |
|
|
Q2 |
|
|
Q1 |
|
|
Year |
|
|
Q4 |
|
|
Q3 |
|
|
Q2 Year- to-date |
|
|
Q2 |
|
|
Q1 |
|
Natural Gas - Canadian Operations ($/Mcf) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price (1) |
|
|
3.23 |
|
|
|
2.39 |
|
|
|
3.89 |
|
|
|
4.89 |
|
|
|
3.93 |
|
|
|
3.78 |
|
|
|
5.77 |
|
|
|
4.27 |
|
|
|
7.17 |
|
Production and mineral taxes |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
0.01 |
|
|
|
0.01 |
|
|
|
0.01 |
|
|
|
0.01 |
|
|
|
- |
|
|
|
0.01 |
|
Transportation and processing |
|
|
1.76 |
|
|
|
1.97 |
|
|
|
1.60 |
|
|
|
1.53 |
|
|
|
1.73 |
|
|
|
1.47 |
|
|
|
1.49 |
|
|
|
1.57 |
|
|
|
1.42 |
|
Operating |
|
|
0.42 |
|
|
|
0.49 |
|
|
|
0.35 |
|
|
|
0.55 |
|
|
|
0.55 |
|
|
|
0.52 |
|
|
|
0.57 |
|
|
|
0.55 |
|
|
|
0.59 |
|
Netback |
|
|
1.05 |
|
|
|
(0.07 |
) |
|
|
1.94 |
|
|
|
2.80 |
|
|
|
1.64 |
|
|
|
1.78 |
|
|
|
3.70 |
|
|
|
2.15 |
|
|
|
5.15 |
|
Natural Gas - USA Operations ($/Mcf) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price |
|
|
2.66 |
|
|
|
2.33 |
|
|
|
2.97 |
|
|
|
4.62 |
|
|
|
3.95 |
|
|
|
4.05 |
|
|
|
5.05 |
|
|
|
4.72 |
|
|
|
5.34 |
|
Production and mineral taxes |
|
|
0.07 |
|
|
|
0.08 |
|
|
|
0.06 |
|
|
|
0.12 |
|
|
|
0.17 |
|
|
|
(0.14 |
) |
|
|
0.21 |
|
|
|
0.15 |
|
|
|
0.26 |
|
Transportation and processing |
|
|
2.29 |
|
|
|
2.27 |
|
|
|
2.30 |
|
|
|
1.83 |
|
|
|
2.16 |
|
|
|
2.13 |
|
|
|
1.62 |
|
|
|
1.80 |
|
|
|
1.46 |
|
Operating |
|
|
0.75 |
|
|
|
0.74 |
|
|
|
0.75 |
|
|
|
0.66 |
|
|
|
0.75 |
|
|
|
0.65 |
|
|
|
0.64 |
|
|
|
0.67 |
|
|
|
0.61 |
|
Netback |
|
|
(0.45 |
) |
|
|
(0.76 |
) |
|
|
(0.14 |
) |
|
|
2.01 |
|
|
|
0.87 |
|
|
|
1.41 |
|
|
|
2.58 |
|
|
|
2.10 |
|
|
|
3.01 |
|
Natural Gas - Total Operations ($/Mcf) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price (2) |
|
|
3.00 |
|
|
|
2.37 |
|
|
|
3.53 |
|
|
|
4.78 |
|
|
|
3.94 |
|
|
|
3.88 |
|
|
|
5.46 |
|
|
|
4.46 |
|
|
|
6.37 |
|
Production and mineral taxes |
|
|
0.03 |
|
|
|
0.04 |
|
|
|
0.02 |
|
|
|
0.06 |
|
|
|
0.08 |
|
|
|
(0.05 |
) |
|
|
0.09 |
|
|
|
0.06 |
|
|
|
0.12 |
|
Transportation and processing |
|
|
1.98 |
|
|
|
2.10 |
|
|
|
1.88 |
|
|
|
1.66 |
|
|
|
1.90 |
|
|
|
1.72 |
|
|
|
1.55 |
|
|
|
1.67 |
|
|
|
1.44 |
|
Operating |
|
|
0.55 |
|
|
|
0.60 |
|
|
|
0.51 |
|
|
|
0.60 |
|
|
|
0.63 |
|
|
|
0.57 |
|
|
|
0.60 |
|
|
|
0.60 |
|
|
|
0.60 |
|
Netback |
|
|
0.44 |
|
|
|
(0.37 |
) |
|
|
1.12 |
|
|
|
2.46 |
|
|
|
1.33 |
|
|
|
1.64 |
|
|
|
3.22 |
|
|
|
2.13 |
|
|
|
4.21 |
|
Oil & NGLs - Canadian Operations ($/bbl) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price |
|
|
34.53 |
|
|
|
38.57 |
|
|
|
30.65 |
|
|
|
64.16 |
|
|
|
57.50 |
|
|
|
64.79 |
|
|
|
66.25 |
|
|
|
66.13 |
|
|
|
66.36 |
|
Production and mineral taxes |
|
|
0.02 |
|
|
|
- |
|
|
|
0.04 |
|
|
|
0.71 |
|
|
|
0.10 |
|
|
|
0.67 |
|
|
|
0.95 |
|
|
|
1.12 |
|
|
|
0.80 |
|
Transportation and processing |
|
|
5.64 |
|
|
|
5.46 |
|
|
|
5.82 |
|
|
|
4.52 |
|
|
|
5.92 |
|
|
|
4.21 |
|
|
|
4.18 |
|
|
|
4.60 |
|
|
|
3.80 |
|
Operating |
|
|
2.12 |
|
|
|
1.91 |
|
|
|
2.31 |
|
|
|
2.09 |
|
|
|
4.00 |
|
|
|
2.05 |
|
|
|
1.42 |
|
|
|
1.06 |
|
|
|
1.75 |
|
Netback |
|
|
26.75 |
|
|
|
31.20 |
|
|
|
22.48 |
|
|
|
56.84 |
|
|
|
47.48 |
|
|
|
57.86 |
|
|
|
59.70 |
|
|
|
59.35 |
|
|
|
60.01 |
|
Oil & NGLs - USA Operations ($/bbl) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price |
|
|
40.43 |
|
|
|
45.21 |
|
|
|
35.18 |
|
|
|
69.54 |
|
|
|
57.30 |
|
|
|
79.43 |
|
|
|
75.67 |
|
|
|
77.46 |
|
|
|
73.61 |
|
Production and mineral taxes |
|
|
2.04 |
|
|
|
2.26 |
|
|
|
1.80 |
|
|
|
4.10 |
|
|
|
3.16 |
|
|
|
4.18 |
|
|
|
5.32 |
|
|
|
5.19 |
|
|
|
5.46 |
|
Transportation and processing |
|
|
0.33 |
|
|
|
0.24 |
|
|
|
0.43 |
|
|
|
0.39 |
|
|
|
0.49 |
|
|
|
0.63 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Operating |
|
|
10.18 |
|
|
|
11.28 |
|
|
|
8.96 |
|
|
|
6.36 |
|
|
|
7.11 |
|
|
|
7.80 |
|
|
|
3.77 |
|
|
|
4.29 |
|
|
|
3.16 |
|
Netback |
|
|
27.88 |
|
|
|
31.43 |
|
|
|
23.99 |
|
|
|
58.69 |
|
|
|
46.54 |
|
|
|
66.82 |
|
|
|
66.58 |
|
|
|
67.98 |
|
|
|
64.99 |
|
Oil & NGLs - Total Operations ($/bbl) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price |
|
|
39.14 |
|
|
|
43.83 |
|
|
|
34.13 |
|
|
|
67.24 |
|
|
|
57.35 |
|
|
|
73.48 |
|
|
|
70.24 |
|
|
|
71.23 |
|
|
|
69.23 |
|
Production and mineral taxes |
|
|
1.60 |
|
|
|
1.79 |
|
|
|
1.40 |
|
|
|
2.65 |
|
|
|
2.35 |
|
|
|
2.75 |
|
|
|
2.80 |
|
|
|
2.95 |
|
|
|
2.65 |
|
Transportation and processing |
|
|
1.49 |
|
|
|
1.32 |
|
|
|
1.67 |
|
|
|
2.16 |
|
|
|
1.93 |
|
|
|
2.09 |
|
|
|
2.41 |
|
|
|
2.53 |
|
|
|
2.30 |
|
Operating |
|
|
8.41 |
|
|
|
9.35 |
|
|
|
7.43 |
|
|
|
4.54 |
|
|
|
6.29 |
|
|
|
5.46 |
|
|
|
2.42 |
|
|
|
2.51 |
|
|
|
2.31 |
|
Netback |
|
|
27.64 |
|
|
|
31.37 |
|
|
|
23.63 |
|
|
|
57.89 |
|
|
|
46.78 |
|
|
|
63.18 |
|
|
|
62.61 |
|
|
|
63.24 |
|
|
|
61.97 |
|
Total Operations Netback - Canadian Operations ($/BOE) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price |
|
|
21.50 |
|
|
|
18.05 |
|
|
|
24.30 |
|
|
|
34.21 |
|
|
|
28.06 |
|
|
|
29.21 |
|
|
|
38.85 |
|
|
|
31.02 |
|
|
|
46.20 |
|
Production and mineral taxes |
|
|
0.01 |
|
|
|
- |
|
|
|
0.02 |
|
|
|
0.15 |
|
|
|
0.09 |
|
|
|
0.15 |
|
|
|
0.17 |
|
|
|
0.16 |
|
|
|
0.18 |
|
Transportation and processing |
|
|
9.90 |
|
|
|
10.85 |
|
|
|
9.12 |
|
|
|
8.55 |
|
|
|
9.79 |
|
|
|
8.10 |
|
|
|
8.30 |
|
|
|
8.76 |
|
|
|
7.87 |
|
Operating |
|
|
2.44 |
|
|
|
2.80 |
|
|
|
2.14 |
|
|
|
3.14 |
|
|
|
3.39 |
|
|
|
2.96 |
|
|
|
3.14 |
|
|
|
2.98 |
|
|
|
3.29 |
|
Netback |
|
|
9.15 |
|
|
|
4.40 |
|
|
|
13.02 |
|
|
|
22.37 |
|
|
|
14.79 |
|
|
|
18.00 |
|
|
|
27.24 |
|
|
|
19.12 |
|
|
|
34.86 |
|
Total Operations Netback - USA Operations ($/BOE) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price |
|
|
26.99 |
|
|
|
28.61 |
|
|
|
25.34 |
|
|
|
37.53 |
|
|
|
36.64 |
|
|
|
41.38 |
|
|
|
36.18 |
|
|
|
35.48 |
|
|
|
36.82 |
|
Production and mineral taxes |
|
|
1.15 |
|
|
|
1.33 |
|
|
|
0.97 |
|
|
|
1.53 |
|
|
|
1.84 |
|
|
|
0.72 |
|
|
|
1.76 |
|
|
|
1.51 |
|
|
|
1.99 |
|
Transportation and processing |
|
|
7.68 |
|
|
|
7.34 |
|
|
|
8.02 |
|
|
|
8.52 |
|
|
|
8.17 |
|
|
|
9.03 |
|
|
|
8.45 |
|
|
|
9.23 |
|
|
|
7.75 |
|
Operating |
|
|
7.05 |
|
|
|
7.66 |
|
|
|
6.44 |
|
|
|
4.53 |
|
|
|
5.51 |
|
|
|
5.12 |
|
|
|
3.81 |
|
|
|
4.05 |
|
|
|
3.60 |
|
Netback |
|
|
11.11 |
|
|
|
12.28 |
|
|
|
9.91 |
|
|
|
22.95 |
|
|
|
21.12 |
|
|
|
26.51 |
|
|
|
22.16 |
|
|
|
20.69 |
|
|
|
23.48 |
|
Total Operations Netback ($/BOE) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price |
|
|
24.38 |
|
|
|
23.90 |
|
|
|
24.82 |
|
|
|
35.67 |
|
|
|
32.25 |
|
|
|
34.36 |
|
|
|
37.70 |
|
|
|
32.93 |
|
|
|
42.12 |
|
Production and mineral taxes |
|
|
0.61 |
|
|
|
0.73 |
|
|
|
0.49 |
|
|
|
0.76 |
|
|
|
0.94 |
|
|
|
0.39 |
|
|
|
0.86 |
|
|
|
0.74 |
|
|
|
0.97 |
|
Transportation and processing |
|
|
8.73 |
|
|
|
8.91 |
|
|
|
8.57 |
|
|
|
8.54 |
|
|
|
9.00 |
|
|
|
8.50 |
|
|
|
8.37 |
|
|
|
8.96 |
|
|
|
7.82 |
|
Operating (3) |
|
|
4.86 |
|
|
|
5.50 |
|
|
|
4.27 |
|
|
|
3.76 |
|
|
|
4.43 |
|
|
|
3.87 |
|
|
|
3.43 |
|
|
|
3.44 |
|
|
|
3.43 |
|
Netback |
|
|
10.18 |
|
|
|
8.76 |
|
|
|
11.49 |
|
|
|
22.61 |
|
|
|
17.88 |
|
|
|
21.60 |
|
|
|
25.04 |
|
|
|
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 107 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 $2.57/Mcf. |
|
(3) |
2015 year-to-date operating expense includes costs related to long-term incentives of $0.01/BOE (2014 year to date - costs of $0.30/BOE).
|
|
|
|
|
|
Supplemental Information
Prepared in US$ |
|
|
|
Q2 Report | For the period ended June 30, 2015
|
|
Supplemental Oil and Gas Operating Statistics (unaudited) |
Operating Statistics - After Royalties (continued)
Impact of Realized Financial Hedging
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2015 |
|
|
2014 |
|
|
|
Year-to- date |
|
|
Q2 |
|
|
Q1 |
|
|
Year |
|
|
Q4 |
|
|
Q3 |
|
|
Q2 Year- to-date |
|
|
Q2 |
|
|
Q1 |
|
|
|
|
|
|
|
|
|
|
|
Natural Gas ($/Mcf) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
|
1.43 |
|
|
|
1.32 |
|
|
|
1.52 |
|
|
|
(0.15 |
) |
|
|
0.24 |
|
|
|
0.16 |
|
|
|
(0.43 |
) |
|
|
(0.33 |
) |
|
|
(0.53 |
) |
USA Operations |
|
|
0.88 |
|
|
|
0.93 |
|
|
|
0.82 |
|
|
|
(0.24 |
) |
|
|
0.19 |
|
|
|
0.12 |
|
|
|
(0.51 |
) |
|
|
(0.44 |
) |
|
|
(0.58 |
) |
Total Operations |
|
|
1.20 |
|
|
|
1.15 |
|
|
|
1.25 |
|
|
|
(0.19 |
) |
|
|
0.22 |
|
|
|
0.15 |
|
|
|
(0.47 |
) |
|
|
(0.38 |
) |
|
|
(0.55 |
) |
Oil & NGLs ($/bbl) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
|
(0.68 |
) |
|
|
(2.21 |
) |
|
|
0.78 |
|
|
|
1.36 |
|
|
|
9.35 |
|
|
|
(0.31 |
) |
|
|
(0.63 |
) |
|
|
(1.22 |
) |
|
|
(0.09 |
) |
USA Operations |
|
|
2.45 |
|
|
|
0.52 |
|
|
|
4.58 |
|
|
|
3.29 |
|
|
|
8.94 |
|
|
|
0.25 |
|
|
|
(1.21 |
) |
|
|
(2.28 |
) |
|
|
0.04 |
|
Total Operations |
|
|
1.77 |
|
|
|
(0.05 |
) |
|
|
3.70 |
|
|
|
2.46 |
|
|
|
9.05 |
|
|
|
0.02 |
|
|
|
(0.88 |
) |
|
|
(1.70 |
) |
|
|
(0.04 |
) |
Total ($/BOE) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
|
7.30 |
|
|
|
6.39 |
|
|
|
8.04 |
|
|
|
(0.57 |
) |
|
|
2.49 |
|
|
|
0.78 |
|
|
|
(2.35 |
) |
|
|
(1.89 |
) |
|
|
(2.77 |
) |
USA Operations |
|
|
3.99 |
|
|
|
3.22 |
|
|
|
4.78 |
|
|
|
(0.33 |
) |
|
|
4.15 |
|
|
|
0.58 |
|
|
|
(2.83 |
) |
|
|
(2.57 |
) |
|
|
(3.07 |
) |
Total Operations |
|
|
5.56 |
|
|
|
4.63 |
|
|
|
6.42 |
|
|
|
(0.46 |
) |
|
|
3.30 |
|
|
|
0.70 |
|
|
|
(2.56 |
) |
|
|
(2.18 |
) |
|
|
(2.90 |
) |
|
Per-unit Results, Including the Impact of Realized Financial Hedging |
|
|
|
|
|
|
2015 |
|
|
2014 |
|
|
|
Year-to- date |
|
|
Q2 |
|
|
Q1 |
|
|
Year |
|
|
Q4 |
|
|
Q3 |
|
|
Q2 Year- to-date |
|
|
Q2 |
|
|
Q1 |
|
Natural Gas Price ($/Mcf) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
|
4.66 |
|
|
|
3.71 |
|
|
|
5.41 |
|
|
|
4.74 |
|
|
|
4.17 |
|
|
|
3.94 |
|
|
|
5.34 |
|
|
|
3.94 |
|
|
|
6.64 |
|
USA Operations |
|
|
3.54 |
|
|
|
3.26 |
|
|
|
3.79 |
|
|
|
4.38 |
|
|
|
4.14 |
|
|
|
4.17 |
|
|
|
4.54 |
|
|
|
4.28 |
|
|
|
4.76 |
|
Total Operations |
|
|
4.20 |
|
|
|
3.52 |
|
|
|
4.78 |
|
|
|
4.59 |
|
|
|
4.16 |
|
|
|
4.03 |
|
|
|
4.99 |
|
|
|
4.08 |
|
|
|
5.82 |
|
Natural Gas Netback ($/Mcf) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
|
2.48 |
|
|
|
1.25 |
|
|
|
3.46 |
|
|
|
2.65 |
|
|
|
1.88 |
|
|
|
1.94 |
|
|
|
3.27 |
|
|
|
1.82 |
|
|
|
4.62 |
|
USA Operations |
|
|
0.43 |
|
|
|
0.17 |
|
|
|
0.68 |
|
|
|
1.77 |
|
|
|
1.06 |
|
|
|
1.53 |
|
|
|
2.07 |
|
|
|
1.66 |
|
|
|
2.43 |
|
Total Operations |
|
|
1.64 |
|
|
|
0.78 |
|
|
|
2.37 |
|
|
|
2.27 |
|
|
|
1.55 |
|
|
|
1.79 |
|
|
|
2.75 |
|
|
|
1.75 |
|
|
|
3.66 |
|
Oil & NGLs Price ($/bbl) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
|
33.85 |
|
|
|
36.36 |
|
|
|
31.43 |
|
|
|
65.52 |
|
|
|
66.85 |
|
|
|
64.48 |
|
|
|
65.62 |
|
|
|
64.91 |
|
|
|
66.27 |
|
USA Operations |
|
|
42.88 |
|
|
|
45.73 |
|
|
|
39.76 |
|
|
|
72.83 |
|
|
|
66.24 |
|
|
|
79.68 |
|
|
|
74.46 |
|
|
|
75.18 |
|
|
|
73.65 |
|
Total Operations |
|
|
40.91 |
|
|
|
43.78 |
|
|
|
37.83 |
|
|
|
69.70 |
|
|
|
66.40 |
|
|
|
73.50 |
|
|
|
69.36 |
|
|
|
69.53 |
|
|
|
69.19 |
|
Oil & NGLs Netback ($/bbl) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
|
26.07 |
|
|
|
28.99 |
|
|
|
23.26 |
|
|
|
58.20 |
|
|
|
56.83 |
|
|
|
57.55 |
|
|
|
59.07 |
|
|
|
58.13 |
|
|
|
59.92 |
|
USA Operations |
|
|
30.33 |
|
|
|
31.95 |
|
|
|
28.57 |
|
|
|
61.98 |
|
|
|
55.48 |
|
|
|
67.07 |
|
|
|
65.37 |
|
|
|
65.70 |
|
|
|
65.03 |
|
Total Operations |
|
|
29.41 |
|
|
|
31.32 |
|
|
|
27.33 |
|
|
|
60.35 |
|
|
|
55.83 |
|
|
|
63.20 |
|
|
|
61.73 |
|
|
|
61.54 |
|
|
|
61.93 |
|
Total Price ($/BOE) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
|
28.80 |
|
|
|
24.44 |
|
|
|
32.34 |
|
|
|
33.64 |
|
|
|
30.55 |
|
|
|
29.99 |
|
|
|
36.50 |
|
|
|
29.13 |
|
|
|
43.43 |
|
USA Operations |
|
|
30.98 |
|
|
|
31.83 |
|
|
|
30.12 |
|
|
|
37.20 |
|
|
|
40.79 |
|
|
|
41.96 |
|
|
|
33.35 |
|
|
|
32.91 |
|
|
|
33.75 |
|
Total Operations |
|
|
29.94 |
|
|
|
28.53 |
|
|
|
31.24 |
|
|
|
35.21 |
|
|
|
35.55 |
|
|
|
35.06 |
|
|
|
35.14 |
|
|
|
30.75 |
|
|
|
39.22 |
|
Total Netback ($/BOE) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
|
16.45 |
|
|
|
10.79 |
|
|
|
21.06 |
|
|
|
21.80 |
|
|
|
17.28 |
|
|
|
18.78 |
|
|
|
24.89 |
|
|
|
17.23 |
|
|
|
32.09 |
|
USA Operations |
|
|
15.10 |
|
|
|
15.50 |
|
|
|
14.69 |
|
|
|
22.62 |
|
|
|
25.27 |
|
|
|
27.09 |
|
|
|
19.33 |
|
|
|
18.12 |
|
|
|
20.41 |
|
Total Operations |
|
|
15.74 |
|
|
|
13.39 |
|
|
|
17.91 |
|
|
|
22.15 |
|
|
|
21.18 |
|
|
|
22.30 |
|
|
|
22.48 |
|
|
|
17.61 |
|
|
|
27.00 |
|
|
|
|
|
|
|
|
Supplemental Information Prepared in US$ |
|
Q2 Report | For the period ended June 30,
2015 |
|
Supplemental Oil and Gas Operating Statistics (unaudited) |
Results by Play
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2015 |
|
|
2014 |
|
|
|
Year-to- date |
|
|
Q2 |
|
|
Q1 |
|
|
Year |
|
|
Q4 |
|
|
Q3 |
|
|
Q2 Year- to-date |
|
|
Q2 |
|
|
Q1 |
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Production (MMcf/d) - After Royalties |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Montney (1) |
|
|
701 |
|
|
|
685 |
|
|
|
717 |
|
|
|
639 |
|
|
|
687 |
|
|
|
644 |
|
|
|
612 |
|
|
|
604 |
|
|
|
620 |
|
Duvernay |
|
|
17 |
|
|
|
17 |
|
|
|
16 |
|
|
|
11 |
|
|
|
12 |
|
|
|
15 |
|
|
|
9 |
|
|
|
9 |
|
|
|
8 |
|
Other Upstream Operations (2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wheatland (3) |
|
|
94 |
|
|
|
76 |
|
|
|
111 |
|
|
|
292 |
|
|
|
249 |
|
|
|
291 |
|
|
|
314 |
|
|
|
305 |
|
|
|
324 |
|
Bighorn |
|
|
2 |
|
|
|
- |
|
|
|
4 |
|
|
|
158 |
|
|
|
(3 |
) |
|
|
162 |
|
|
|
238 |
|
|
|
230 |
|
|
|
246 |
|
Deep Panuke |
|
|
107 |
|
|
|
32 |
|
|
|
182 |
|
|
|
190 |
|
|
|
79 |
|
|
|
186 |
|
|
|
248 |
|
|
|
243 |
|
|
|
253 |
|
Other and emerging (1) |
|
|
83 |
|
|
|
71 |
|
|
|
98 |
|
|
|
88 |
|
|
|
87 |
|
|
|
76 |
|
|
|
95 |
|
|
|
72 |
|
|
|
117 |
|
Total Canadian Operations |
|
|
1,004 |
|
|
|
881 |
|
|
|
1,128 |
|
|
|
1,378 |
|
|
|
1,111 |
|
|
|
1,374 |
|
|
|
1,516 |
|
|
|
1,463 |
|
|
|
1,568 |
|
|
|
|
|
|
|
|
|
|
|
USA Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Eagle Ford |
|
|
36 |
|
|
|
36 |
|
|
|
36 |
|
|
|
19 |
|
|
|
35 |
|
|
|
35 |
|
|
|
2 |
|
|
|
5 |
|
|
|
- |
|
Permian |
|
|
36 |
|
|
|
38 |
|
|
|
34 |
|
|
|
5 |
|
|
|
20 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
DJ Basin |
|
|
52 |
|
|
|
55 |
|
|
|
49 |
|
|
|
43 |
|
|
|
49 |
|
|
|
38 |
|
|
|
42 |
|
|
|
43 |
|
|
|
40 |
|
San Juan |
|
|
14 |
|
|
|
15 |
|
|
|
13 |
|
|
|
8 |
|
|
|
8 |
|
|
|
9 |
|
|
|
7 |
|
|
|
7 |
|
|
|
7 |
|
Other Upstream Operations (2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Piceance |
|
|
333 |
|
|
|
324 |
|
|
|
343 |
|
|
|
402 |
|
|
|
367 |
|
|
|
398 |
|
|
|
421 |
|
|
|
407 |
|
|
|
436 |
|
Haynesville |
|
|
217 |
|
|
|
204 |
|
|
|
230 |
|
|
|
311 |
|
|
|
252 |
|
|
|
298 |
|
|
|
348 |
|
|
|
365 |
|
|
|
331 |
|
Jonah |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
100 |
|
|
|
- |
|
|
|
- |
|
|
|
203 |
|
|
|
124 |
|
|
|
282 |
|
East Texas |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
57 |
|
|
|
- |
|
|
|
21 |
|
|
|
105 |
|
|
|
97 |
|
|
|
113 |
|
Other and emerging |
|
|
20 |
|
|
|
15 |
|
|
|
24 |
|
|
|
27 |
|
|
|
19 |
|
|
|
26 |
|
|
|
31 |
|
|
|
30 |
|
|
|
32 |
|
Total USA Operations |
|
|
708 |
|
|
|
687 |
|
|
|
729 |
|
|
|
972 |
|
|
|
750 |
|
|
|
825 |
|
|
|
1,159 |
|
|
|
1,078 |
|
|
|
1,241 |
|
|
|
|
|
|
|
|
|
|
|
Oil & NGLs Production (Mbbls/d) - After Royalties |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Montney (1) |
|
|
22.5 |
|
|
|
21.6 |
|
|
|
23.3 |
|
|
|
18.9 |
|
|
|
24.8 |
|
|
|
20.8 |
|
|
|
14.8 |
|
|
|
13.3 |
|
|
|
16.2 |
|
Duvernay |
|
|
2.9 |
|
|
|
3.0 |
|
|
|
2.8 |
|
|
|
2.1 |
|
|
|
2.5 |
|
|
|
2.6 |
|
|
|
1.6 |
|
|
|
1.8 |
|
|
|
1.4 |
|
Other Upstream Operations (2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wheatland (3) |
|
|
1.5 |
|
|
|
1.2 |
|
|
|
1.7 |
|
|
|
8.6 |
|
|
|
2.0 |
|
|
|
9.9 |
|
|
|
11.3 |
|
|
|
11.3 |
|
|
|
11.3 |
|
Bighorn |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
7.5 |
|
|
|
(1.5 |
) |
|
|
8.7 |
|
|
|
11.5 |
|
|
|
11.0 |
|
|
|
12.1 |
|
Other and emerging (1) |
|
|
0.1 |
|
|
|
0.5 |
|
|
|
- |
|
|
|
0.1 |
|
|
|
0.4 |
|
|
|
0.3 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Total Canadian Operations |
|
|
27.0 |
|
|
|
26.3 |
|
|
|
27.8 |
|
|
|
37.2 |
|
|
|
28.2 |
|
|
|
42.3 |
|
|
|
39.2 |
|
|
|
37.4 |
|
|
|
41.0 |
|
|
|
|
|
|
|
|
|
|
|
USA Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Eagle Ford |
|
|
37.9 |
|
|
|
39.8 |
|
|
|
36.0 |
|
|
|
19.8 |
|
|
|
36.1 |
|
|
|
37.6 |
|
|
|
2.5 |
|
|
|
5.0 |
|
|
|
- |
|
Permian |
|
|
28.1 |
|
|
|
29.5 |
|
|
|
26.7 |
|
|
|
3.5 |
|
|
|
13.8 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
DJ Basin |
|
|
14.8 |
|
|
|
15.3 |
|
|
|
14.3 |
|
|
|
11.6 |
|
|
|
14.0 |
|
|
|
11.8 |
|
|
|
10.3 |
|
|
|
10.1 |
|
|
|
10.5 |
|
San Juan |
|
|
6.6 |
|
|
|
6.4 |
|
|
|
6.7 |
|
|
|
3.9 |
|
|
|
5.6 |
|
|
|
3.5 |
|
|
|
3.3 |
|
|
|
3.9 |
|
|
|
2.7 |
|
Other Upstream Operations (2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Piceance |
|
|
3.7 |
|
|
|
3.7 |
|
|
|
3.7 |
|
|
|
5.0 |
|
|
|
4.3 |
|
|
|
4.8 |
|
|
|
5.4 |
|
|
|
5.3 |
|
|
|
5.4 |
|
Jonah |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
1.8 |
|
|
|
- |
|
|
|
0.2 |
|
|
|
3.6 |
|
|
|
2.5 |
|
|
|
4.7 |
|
East Texas |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
0.5 |
|
|
|
- |
|
|
|
- |
|
|
|
1.1 |
|
|
|
1.0 |
|
|
|
1.2 |
|
Other and emerging |
|
|
5.9 |
|
|
|
6.3 |
|
|
|
5.5 |
|
|
|
3.5 |
|
|
|
4.4 |
|
|
|
3.8 |
|
|
|
2.6 |
|
|
|
3.0 |
|
|
|
2.4 |
|
Total USA Operations |
|
|
97.0 |
|
|
|
101.0 |
|
|
|
92.9 |
|
|
|
49.6 |
|
|
|
78.2 |
|
|
|
61.7 |
|
|
|
28.8 |
|
|
|
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$ |
|
|
|
Q2 Report | For the period ended June 30, 2015
|
|
Supplemental Oil and Gas Operating Statistics (unaudited) |
Results by Play (continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2015 |
|
|
2014 |
|
|
|
Year-to- date |
|
|
Q2 |
|
|
Q1 |
|
|
Year |
|
|
Q4 |
|
|
Q3 |
|
|
Q2 Year- to-date |
|
|
Q2 |
|
|
Q1 |
|
|
|
|
|
|
|
|
|
|
|
Drilling Activity (net wells drilled) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Montney |
|
|
14 |
|
|
|
6 |
|
|
|
8 |
|
|
|
79 |
|
|
|
14 |
|
|
|
15 |
|
|
|
50 |
|
|
|
23 |
|
|
|
27 |
|
Duvernay |
|
|
7 |
|
|
|
1 |
|
|
|
6 |
|
|
|
24 |
|
|
|
5 |
|
|
|
7 |
|
|
|
12 |
|
|
|
6 |
|
|
|
6 |
|
Other Upstream Operations (1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wheatland (2) |
|
|
71 |
|
|
|
- |
|
|
|
71 |
|
|
|
174 |
|
|
|
84 |
|
|
|
24 |
|
|
|
66 |
|
|
|
- |
|
|
|
66 |
|
Bighorn |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
1 |
|
|
|
- |
|
|
|
1 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Other and emerging |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
1 |
|
|
|
- |
|
|
|
1 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Total Canadian Operations |
|
|
92 |
|
|
|
7 |
|
|
|
85 |
|
|
|
279 |
|
|
|
103 |
|
|
|
48 |
|
|
|
128 |
|
|
|
29 |
|
|
|
99 |
|
|
|
|
|
|
|
|
|
|
|
USA Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Eagle Ford |
|
|
41 |
|
|
|
14 |
|
|
|
27 |
|
|
|
35 |
|
|
|
21 |
|
|
|
14 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Permian |
|
|
98 |
|
|
|
52 |
|
|
|
46 |
|
|
|
28 |
|
|
|
28 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
DJ Basin |
|
|
15 |
|
|
|
2 |
|
|
|
13 |
|
|
|
64 |
|
|
|
15 |
|
|
|
17 |
|
|
|
32 |
|
|
|
14 |
|
|
|
18 |
|
San Juan |
|
|
1 |
|
|
|
- |
|
|
|
1 |
|
|
|
43 |
|
|
|
19 |
|
|
|
15 |
|
|
|
9 |
|
|
|
5 |
|
|
|
4 |
|
Other Upstream Operations (1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Piceance |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
1 |
|
|
|
- |
|
|
|
- |
|
|
|
1 |
|
|
|
- |
|
|
|
1 |
|
Haynesville |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Jonah |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
18 |
|
|
|
- |
|
|
|
- |
|
|
|
18 |
|
|
|
6 |
|
|
|
12 |
|
East Texas |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Other and emerging |
|
|
3 |
|
|
|
- |
|
|
|
3 |
|
|
|
15 |
|
|
|
5 |
|
|
|
4 |
|
|
|
6 |
|
|
|
4 |
|
|
|
2 |
|
Total USA Operations |
|
|
158 |
|
|
|
68 |
|
|
|
90 |
|
|
|
204 |
|
|
|
88 |
|
|
|
50 |
|
|
|
66 |
|
|
|
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 (NYSE:ECA)
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