The MD&A is intended to provide a narrative description of Encanas business from managements perspective. This MD&A should
be read in conjunction with the unaudited interim Condensed Consolidated Financial Statements and accompanying notes for the period ended June 30, 2017 (Consolidated Financial Statements), which are included in Part I, Item 1
of this Quarterly Report on Form 10-Q and the audited Consolidated Financial Statements and accompanying notes and MD&A for the year ended December 31, 2016, which are included in Items 8 and 7, respectively, of the 2016 Annual Report on
Form 10-K. Common industry terms and abbreviations are used throughout this MD&A and are defined in the Definitions, Conversions and Conventions sections of this Quarterly Report on Form 10-Q. This MD&A includes the following sections:
Encana is a leading North American
energy producer that is focused on developing its multi-basin portfolio of oil, NGL and natural gas producing plays. 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 exercising a disciplined capital allocation strategy by investing in a limited number of core assets, growing high margin liquids volumes, maximizing profitability through operating efficiencies and
reducing costs, and preserving balance sheet strength.
In executing its strategy, Encana focuses on its core values of One, Agile and
Driven, which guide the organization to be flexible, responsive, determined and motivated with a commitment to excellence and a passion to succeed as a unified team.
Encana continually reviews and evaluates its strategy and changing market conditions. In 2017, Encana continues to focus on quality growth
from high margin, scalable projects located in some of the best plays in North America, referred to as the Core Assets, comprising Montney and Duvernay in Canada and Eagle Ford and Permian in the U.S. These world-class assets form a
multi-basin portfolio enabling flexible and efficient investment of capital. The Company rapidly deploys successful ideas and practices across these assets, becoming more efficient as innovative and sustainable technical improvements are
implemented.
For additional information on Encanas strategy, its reporting segments and the plays in which the Company operates,
refer to Items 1 and 2 of the 2016 Annual Report on Form 10-K. In evaluating its operations, the Company reviews performance-based measures such as Non-GAAP Cash Flow and Corporate Margin, which are non-GAAP measures and do not have any standardized
meaning under U.S. GAAP. These measures may not be similar to measures presented by other issuers and should not be viewed as a substitute for measures reported under U.S. GAAP. Further information regarding these measures, including reconciliations
to the closest GAAP measure, can be found in the Non-GAAP Measures section of this MD&A.
During the first six months of
2017, Encana focused on executing its 2017 capital plan, maintaining operational efficiencies achieved in 2016 and seeking new ways to reduce costs. Higher benchmark prices in the first six months of 2017 compared to 2016 contributed to increases in
Encanas average realized oil, NGLs and natural gas prices which resulted in higher revenues. In the first six months of 2017, Encanas average realized oil, NGLs and natural gas prices increased by 40 percent, 62 percent and 71 percent,
respectively, compared to 2016. Encana remains committed to building a business model that allows the Company to adapt to fluctuating commodity prices.
The oil and gas industry is cyclical and commodity prices are inherently volatile. Oil prices during the second half of 2017
are expected to reflect global supply and demand dynamics as well as the geopolitical environment. At a meeting in May, OPEC decided to extend an agreement among members and certain non-OPEC countries to cut crude oil production until the end of the
first quarter of 2018. The agreement, which was implemented in January 2017, has been generally supportive of oil prices in early 2017; however, production growth in other countries continues to partially offset the expected benefit of the OPEC
agreement. In addition, rapid increases in U.S. crude oil production or the continuation of elevated levels of U.S. oil storage inventories could also negatively impact prices.
Natural gas prices were stronger in the first half of 2017 compared to 2016 as increases in exports and industrial demand coupled with lower
natural gas production alleviated much of the oversupply. After declining in 2016, natural gas production in the contiguous U.S. is expected to grow as pipeline infrastructure additions in the U.S. Northeast alleviate bottlenecks in the region.
Continued improvement in prices through 2018 depends on the timing of supply and demand growth; however, incremental natural gas production is expected to be sufficient to supply continued demand growth and support natural gas prices at relatively
stronger levels than 2016.
Encana has positioned itself to be flexible and to continue to achieve strong returns from the Core Assets through this evolving commodity
price cycle. The Company released updated Corporate Guidance on July 21, 2017 to reflect the impact of divestitures and improved operational performance which included changes to liquids and natural gas production volumes, upstream operating
expense, transportation and processing expense and production growth from the Core Assets compared to Corporate Guidance previously released in February 2017. The details of Encanas Corporate Guidance can be accessed on the Companys
website at
www.encana.com.
Encana enters into commodity derivative financial instruments on a portion of its expected oil, NGL and natural gas production volumes to
reduce volatility and help sustain revenues during periods of lower prices. As of June 30, 2017, Encanas 2017 commodity price mitigation program covers over 75 percent of expected total production for the remainder of the year.
Encana is on track to meet its full year capital investment guidance of $1.6 billion to $1.8 billion. During the first six months of 2017, the
Company spent $814 million, of which 96 percent was invested in the Core Assets with 52 percent directed to Permian where the Company has drilled 64 net wells. Encana continually strives to improve well performance by lowering drilling and
completion costs through innovative techniques such as the cube development model, characterized as a multi-well pad centralized development on a stacked pay resource. This approach, which is currently being applied in Permian and Montney, is
helping to boost productivity and enhance recovery from reservoirs in those assets.
During the first six months of 2017, average liquids production volumes of 118.0 Mbbls/d were below the updated full year guidance range of
127.0 Mbbls/d to 132.0 Mbbls/d as expected. The Company is on track to meet the updated full year liquids production guidance primarily due to growing Permian oil volumes and liquids volumes in Montney with the anticipated completion of new
facilities in Montney. Average natural gas production volumes of 1,194 MMcf/d exceeded the updated full year 2017 guidance range of 1,075 MMcf/d to 1,125 MMcf/d; Encana expects to be within the updated full year 2017 guidance range after the
Piceance asset sale closes in the third quarter of 2017.
Core Assets production of 242.0 MBOE/d was up slightly compared to the fourth
quarter of 2016 and is expected to grow as Encana sees the anticipated benefit of its increased capital program with additional wells coming online and the anticipated completion of new facilities in Montney. Total liquids production accounted for
37 percent of the Companys total production volumes, with the Core Assets contributing 111.0 Mbbls/d or 94 percent.
To date, efficiency improvements and lower service costs have been maintained and the Company continues to benefit from transportation
contract renegotiations completed in 2016. The Company reported operating costs for the first six months of 2017 which are on track to meet the updated full year 2017 guidance ranges. Transportation and processing expense was $6.53 per BOE, while
upstream operating expense and administrative expense, excluding long-term incentive costs, were $3.79 per BOE and $1.56 per BOE, respectively. Encana continues to offset any inflationary pressures with additional efficiency gains.
Selected Financial Information
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30,
|
|
|
|
|
|
Six months ended June 30,
|
|
($ millions)
|
|
2017
|
|
|
2016
|
|
|
|
|
|
2017
|
|
|
2016
|
|
|
|
|
|
|
|
Product Revenues
|
|
$
|
728
|
|
|
$
|
578
|
|
|
|
|
|
|
$
|
1,466
|
|
|
$
|
1,097
|
|
Gains (Losses) on Risk Management, net
|
|
|
129
|
|
|
|
(330)
|
|
|
|
|
|
|
|
467
|
|
|
|
(207)
|
|
Market Optimization
|
|
|
204
|
|
|
|
91
|
|
|
|
|
|
|
|
390
|
|
|
|
178
|
|
Other
|
|
|
22
|
|
|
|
25
|
|
|
|
|
|
|
|
49
|
|
|
|
49
|
|
Total Revenues
|
|
|
1,083
|
|
|
|
364
|
|
|
|
|
|
|
|
2,372
|
|
|
|
1,117
|
|
|
|
|
|
|
|
Total Operating Expenses
(1)
|
|
|
762
|
|
|
|
1,276
|
|
|
|
|
|
|
|
1,562
|
|
|
|
3,072
|
|
Operating Income (Loss)
|
|
|
321
|
|
|
|
(912)
|
|
|
|
|
|
|
|
810
|
|
|
|
(1,955)
|
|
Total Other (Income) Expenses
|
|
|
(6)
|
|
|
|
156
|
|
|
|
|
|
|
|
49
|
|
|
|
(207)
|
|
Net Earnings (Loss) Before Income Tax
|
|
$
|
327
|
|
|
$
|
(1,068)
|
|
|
|
|
|
|
$
|
761
|
|
|
$
|
(1,748)
|
|
Net Earnings (Loss)
|
|
$
|
331
|
|
|
$
|
(601)
|
|
|
|
|
|
|
$
|
762
|
|
|
$
|
(980)
|
|
(1) Total Operating Expenses include non-cash items such as DD&A, impairments, accretion of
asset retirement obligations and long-term incentive costs.
|
|
Revenues
Encanas revenues are substantially derived from sales of oil, NGL and natural gas production. Increases or decreases in Encanas
revenue, profitability and future production are highly dependent on the commodity prices the Company receives. Prices are market driven and fluctuate due to factors beyond the Companys control, such as supply and demand, seasonality and
geopolitical and economic factors. Canadian Operations realized prices are closely linked to the Edmonton Condensate and AECO benchmark prices, except for production from Deep Panuke which is closely related to the Algonquin City Gate benchmark
price due to the proximity of the offshore production platform to New England. The USA Operations realized prices generally reflect WTI and NYMEX benchmark prices. Realized NGL prices are significantly influenced by oil benchmark prices and the NGL
production mix. Recent trends in benchmark prices relevant to Encana are shown in the table below:
Benchmark Prices
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30,
|
|
|
|
|
|
Six months ended June 30,
|
|
(average for the period)
|
|
2017
|
|
|
2016
|
|
|
|
|
|
2017
|
|
|
2016
|
|
|
|
|
|
|
|
Oil & NGLs
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WTI ($/bbl)
|
|
$
|
48.29
|
|
|
$
|
45.59
|
|
|
|
|
|
|
$
|
50.10
|
|
|
$
|
39.52
|
|
Edmonton Condensate (C$/bbl)
|
|
|
64.59
|
|
|
|
56.80
|
|
|
|
|
|
|
|
66.87
|
|
|
|
52.02
|
|
|
|
|
|
|
|
Natural Gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NYMEX ($/MMBtu)
|
|
$
|
3.18
|
|
|
$
|
1.95
|
|
|
|
|
|
|
$
|
3.25
|
|
|
$
|
2.02
|
|
AECO (C$/Mcf)
|
|
|
2.77
|
|
|
|
1.25
|
|
|
|
|
|
|
|
2.86
|
|
|
|
1.68
|
|
Algonquin City Gate ($/MMBtu)
|
|
|
2.88
|
|
|
|
2.44
|
|
|
|
|
|
|
|
3.67
|
|
|
|
2.86
|
|
37
Production Volumes and Realized Prices
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30,
|
|
|
|
|
|
Six months ended June 30,
|
|
|
|
Production Volumes
(1)
|
|
|
|
|
|
Realized Prices
(2)
|
|
|
|
|
|
Production Volumes
(1)
|
|
|
|
|
|
Realized Prices
(2)
|
|
|
|
2017
|
|
|
2016
|
|
|
|
|
|
2017
|
|
|
2016
|
|
|
|
|
|
2017
|
|
|
2016
|
|
|
|
|
|
2017
|
|
|
2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
(Mbbls/d, $/bbl)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations
|
|
|
0.4
|
|
|
|
3.3
|
|
|
|
|
|
|
$
|
40.23
|
|
|
$
|
41.73
|
|
|
|
|
|
|
|
0.4
|
|
|
|
3.3
|
|
|
|
|
|
|
$
|
41.77
|
|
|
$
|
35.74
|
|
USA Operations
|
|
|
77.0
|
|
|
|
75.6
|
|
|
|
|
|
|
|
46.14
|
|
|
|
40.61
|
|
|
|
|
|
|
|
72.0
|
|
|
|
76.4
|
|
|
|
|
|
|
|
47.75
|
|
|
|
34.12
|
|
Total
|
|
|
77.4
|
|
|
|
78.9
|
|
|
|
|
|
|
|
46.11
|
|
|
|
40.65
|
|
|
|
|
|
|
|
72.4
|
|
|
|
79.7
|
|
|
|
|
|
|
|
47.72
|
|
|
|
34.19
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGLs Plant Condensate
(Mbbls/d, $/bbl)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations
|
|
|
20.5
|
|
|
|
17.7
|
|
|
|
|
|
|
|
46.94
|
|
|
|
44.60
|
|
|
|
|
|
|
|
19.6
|
|
|
|
17.1
|
|
|
|
|
|
|
|
48.53
|
|
|
|
38.67
|
|
USA Operations
|
|
|
2.3
|
|
|
|
3.0
|
|
|
|
|
|
|
|
41.07
|
|
|
|
32.16
|
|
|
|
|
|
|
|
2.1
|
|
|
|
2.8
|
|
|
|
|
|
|
|
41.86
|
|
|
|
27.67
|
|
Total
|
|
|
22.8
|
|
|
|
20.7
|
|
|
|
|
|
|
|
46.34
|
|
|
|
42.82
|
|
|
|
|
|
|
|
21.7
|
|
|
|
19.9
|
|
|
|
|
|
|
|
47.89
|
|
|
|
37.14
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGLs Other
(Mbbls/d, $/bbl)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations
|
|
|
4.7
|
|
|
|
9.4
|
|
|
|
|
|
|
|
19.10
|
|
|
|
9.42
|
|
|
|
|
|
|
|
4.9
|
|
|
|
9.9
|
|
|
|
|
|
|
|
20.91
|
|
|
|
7.48
|
|
USA Operations
|
|
|
20.0
|
|
|
|
23.0
|
|
|
|
|
|
|
|
16.06
|
|
|
|
11.46
|
|
|
|
|
|
|
|
19.0
|
|
|
|
21.9
|
|
|
|
|
|
|
|
17.97
|
|
|
|
10.26
|
|
Total
|
|
|
24.7
|
|
|
|
32.4
|
|
|
|
|
|
|
|
16.65
|
|
|
|
10.87
|
|
|
|
|
|
|
|
23.9
|
|
|
|
31.8
|
|
|
|
|
|
|
|
18.57
|
|
|
|
9.40
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total NGLs
(Mbbls/d, $/bbl)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations
|
|
|
25.2
|
|
|
|
27.1
|
|
|
|
|
|
|
|
41.73
|
|
|
|
32.38
|
|
|
|
|
|
|
|
24.5
|
|
|
|
27.0
|
|
|
|
|
|
|
|
43.01
|
|
|
|
27.21
|
|
USA Operations
|
|
|
22.3
|
|
|
|
26.0
|
|
|
|
|
|
|
|
18.68
|
|
|
|
13.82
|
|
|
|
|
|
|
|
21.1
|
|
|
|
24.7
|
|
|
|
|
|
|
|
20.34
|
|
|
|
12.21
|
|
Total
|
|
|
47.5
|
|
|
|
53.1
|
|
|
|
|
|
|
|
30.93
|
|
|
|
23.29
|
|
|
|
|
|
|
|
45.6
|
|
|
|
51.7
|
|
|
|
|
|
|
|
32.54
|
|
|
|
20.05
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Oil & NGLs
(Mbbls/d, $/bbl)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations
|
|
|
25.6
|
|
|
|
30.4
|
|
|
|
|
|
|
|
41.71
|
|
|
|
33.40
|
|
|
|
|
|
|
|
24.9
|
|
|
|
30.3
|
|
|
|
|
|
|
|
43.00
|
|
|
|
28.13
|
|
USA Operations
|
|
|
99.3
|
|
|
|
101.6
|
|
|
|
|
|
|
|
40.00
|
|
|
|
33.76
|
|
|
|
|
|
|
|
93.1
|
|
|
|
101.1
|
|
|
|
|
|
|
|
41.55
|
|
|
|
28.77
|
|
Total
|
|
|
124.9
|
|
|
|
132.0
|
|
|
|
|
|
|
|
40.35
|
|
|
|
33.67
|
|
|
|
|
|
|
|
118.0
|
|
|
|
131.4
|
|
|
|
|
|
|
|
41.86
|
|
|
|
28.63
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas
(MMcf/d, $/Mcf)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations
|
|
|
785
|
|
|
|
971
|
|
|
|
|
|
|
|
2.33
|
|
|
|
1.18
|
|
|
|
|
|
|
|
835
|
|
|
|
1,018
|
|
|
|
|
|
|
|
2.43
|
|
|
|
1.43
|
|
USA Operations
|
|
|
361
|
|
|
|
447
|
|
|
|
|
|
|
|
3.09
|
|
|
|
1.74
|
|
|
|
|
|
|
|
359
|
|
|
|
448
|
|
|
|
|
|
|
|
3.16
|
|
|
|
1.81
|
|
Total
|
|
|
1,146
|
|
|
|
1,418
|
|
|
|
|
|
|
|
2.57
|
|
|
|
1.35
|
|
|
|
|
|
|
|
1,194
|
|
|
|
1,466
|
|
|
|
|
|
|
|
2.65
|
|
|
|
1.55
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Production
(MBOE/d, $/BOE)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Operations
|
|
|
156.6
|
|
|
|
192.2
|
|
|
|
|
|
|
|
18.52
|
|
|
|
11.23
|
|
|
|
|
|
|
|
164.1
|
|
|
|
200.0
|
|
|
|
|
|
|
|
18.89
|
|
|
|
11.55
|
|
USA Operations
|
|
|
159.4
|
|
|
|
176.1
|
|
|
|
|
|
|
|
31.92
|
|
|
|
23.89
|
|
|
|
|
|
|
|
152.8
|
|
|
|
175.8
|
|
|
|
|
|
|
|
32.71
|
|
|
|
21.16
|
|
Total
|
|
|
316.0
|
|
|
|
368.3
|
|
|
|
|
|
|
|
25.29
|
|
|
|
17.29
|
|
|
|
|
|
|
|
316.9
|
|
|
|
375.8
|
|
|
|
|
|
|
|
25.55
|
|
|
|
16.05
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production Mix
(%)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil & Plant Condensate
|
|
|
32
|
|
|
|
27
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
30
|
|
|
|
27
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGLs Other
|
|
|
8
|
|
|
|
9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7
|
|
|
|
8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Oil & NGLs
|
|
|
40
|
|
|
|
36
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
37
|
|
|
|
35
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas
|
|
|
60
|
|
|
|
64
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
63
|
|
|
|
65
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Core Assets Production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Mbbls/d)
|
|
|
73.6
|
|
|
|
67.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
67.9
|
|
|
|
66.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGLs Plant Condensate (Mbbls/d)
|
|
|
22.4
|
|
|
|
19.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
21.1
|
|
|
|
18.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGLs Other (Mbbls/d)
|
|
|
22.8
|
|
|
|
25.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
22.0
|
|
|
|
24.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total NGLs (Mbbls/d)
|
|
|
45.2
|
|
|
|
44.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
43.1
|
|
|
|
43.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Oil & NGLs (Mbbls/d)
|
|
|
118.8
|
|
|
|
111.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
111.0
|
|
|
|
109.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas (MMcf/d)
|
|
|
768
|
|
|
|
940
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
786
|
|
|
|
952
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Production (MBOE/d)
|
|
|
246.5
|
|
|
|
268.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
242.0
|
|
|
|
268.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
% of Total Encana Production
|
|
|
78
|
|
|
|
73
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
76
|
|
|
|
72
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2)
|
Average per-unit prices, excluding the impact of risk management activities.
|
38
Product Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30,
|
|
|
|
|
|
Six months ended June 30,
|
|
|
|
|
|
|
|
|
|
Natural
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
|
|
|
|
|
($ millions)
|
|
Oil
|
|
|
NGLs
(1)
|
|
|
Gas
|
|
|
Total
|
|
|
|
|
|
Oil
|
|
|
NGLs
(1)
|
|
|
Gas
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
2016 Product Revenues
|
|
$
|
292
|
|
|
$
|
113
|
|
|
$
|
173
|
|
|
$
|
578
|
|
|
|
|
|
|
$
|
495
|
|
|
$
|
189
|
|
|
$
|
413
|
|
|
$
|
1,097
|
|
Increase (decrease) due to:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales prices
|
|
|
38
|
|
|
|
32
|
|
|
|
127
|
|
|
|
197
|
|
|
|
|
|
|
|
179
|
|
|
|
101
|
|
|
|
236
|
|
|
|
516
|
|
Production volumes
|
|
|
(5
|
)
|
|
|
(10
|
)
|
|
|
(32
|
)
|
|
|
(47
|
)
|
|
|
|
|
|
|
(49
|
)
|
|
|
(21
|
)
|
|
|
(77
|
)
|
|
|
(147
|
)
|
2017 Product Revenues
|
|
$
|
325
|
|
|
$
|
135
|
|
|
$
|
268
|
|
|
$
|
728
|
|
|
|
|
|
|
$
|
625
|
|
|
$
|
269
|
|
|
$
|
572
|
|
|
$
|
1,466
|
|
(1) Includes plant condensate.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil Revenues
Three months ended June 30, 2017 versus June 30, 2016
Oil revenues increased $33 million compared to the second quarter of 2016 primarily due to:
|
●
|
|
Higher average realized oil prices of $5.46 per bbl, or 13 percent, increased revenues by $38 million. The
increase reflected a higher WTI benchmark price which was up six percent. The increase was also due to higher utilization of pipelines to transport oil to more favourable markets to receive a higher net price, as well as improved regional pricing in
the USA Operations;
|
partially offset by:
|
●
|
|
Lower average oil production volumes of 1.5 Mbbls/d decreased revenues by $5 million. Lower volumes were
primarily due to the sales of the DJ Basin (4.9 Mbbls/d) and Gordondale assets (2.4 Mbbls/d) in the third quarter of 2016, natural declines primarily in the USA Other Upstream Operations (1.6 Mbbls/d) and the sale of the Tuscaloosa Marine Shale
assets in the second quarter of 2017 (1.3 Mbbls/d), partially offset by successful drilling programs in Permian (8.5 Mbbls/d) and Eagle Ford (1.1 Mbbls/d).
|
Six months ended June 30, 2017 versus June 30, 2016
Oil revenues increased $130 million compared to the first six months of 2016 primarily due to:
|
●
|
|
Higher average realized oil prices of $13.53 per bbl, or 40 percent, increased revenues by $179 million. The
increase reflected a higher WTI benchmark price which was up 27 percent. The increase was also due to higher utilization of pipelines to transport oil to more favourable markets to receive a higher net price, as well as improved regional pricing in
the USA Operations;
|
partially offset by:
|
●
|
|
Lower average oil production volumes of 7.3 Mbbls/d decreased revenues by $49 million. Lower volumes were
primarily due to the sales of the DJ Basin (4.9 Mbbls/d) and Gordondale assets (2.4 Mbbls/d) in the third quarter of 2016, natural declines in Eagle Ford (4.1 Mbbls/d) and in the USA Other Upstream Operations (2.7 Mbbls/d), as well as the sale of
the Tuscaloosa Marine Shale assets in the second quarter of 2017 (1.0 Mbbls/d), partially offset by a successful drilling program in Permian (8.1 Mbbls/d).
|
39
NGL Revenues
Three months ended June 30, 2017 versus June 30, 2016
NGL revenues increased $22 million compared to the second quarter of 2016 primarily due to:
|
●
|
|
Higher average realized NGL prices of $7.64 per bbl, or 33 percent, increased revenues by $32 million. The
increase reflected higher WTI and Edmonton Condensate benchmark prices which were up six percent and 14 percent, respectively. The increase was also due to a shift in the NGL production mix to higher value condensate compared to 2016;
|
partially offset by:
|
●
|
|
Lower average NGL production volumes of 5.6 Mbbls/d decreased revenues by $10 million. Lower volumes were
primarily due to the sales of the Gordondale (5.7 Mbbls/d) and DJ Basin assets (4.9 Mbbls/d) in the third quarter of 2016, partially offset by successful drilling programs in the Core Assets (6.6 Mbbls/d).
|
Six months ended June 30, 2017 versus June 30, 2016
NGL revenues increased $80 million compared to the first six months of 2016 primarily due to:
|
●
|
|
Higher average realized NGL prices of $12.49 per bbl, or 62 percent, increased revenues by $101 million. The
increase reflected higher WTI and Edmonton Condensate benchmark prices which were up 27 percent and 29 percent, respectively. The increase was also due to a shift in the NGL production mix to higher value condensate compared to 2016;
|
partially offset by:
|
●
|
|
Lower average NGL production volumes of 6.1 Mbbls/d decreased revenues by $21 million. Lower volumes were
primarily due to the sales of the Gordondale (5.7 Mbbls/d) and DJ Basin assets (4.9 Mbbls/d) in the third quarter of 2016, partially offset by successful drilling programs in the Core Assets (6.1 Mbbls/d).
|
Natural Gas Revenues
Three months ended June 30, 2017 versus June 30, 2016
Natural gas revenues increased $95 million compared to the
second quarter of 2016 primarily due to:
|
●
|
|
Higher average realized natural gas prices of $1.22 per Mcf, or 90 percent, increased revenues by $127
million. The increase reflected higher NYMEX, AECO and Algonquin City Gate benchmark prices which were up 63 percent, 122 percent and 18 percent, respectively;
|
partially offset by:
|
●
|
|
Lower average natural gas production volumes of 272 MMcf/d decreased revenues by $32 million. Lower volumes
were primarily due to the sales of the Gordondale (79 MMcf/d) and DJ Basin assets (47 MMcf/d) in the third quarter of 2016, increased downtime resulting from scheduled third-party plant maintenance in Montney (74 MMcf/d), natural declines in Other
Upstream Operations (55 MMcf/d) and lower natural gas volumes in Montney due to natural declines and Encanas focus on liquids rich wells in the play (25 MMcf/d).
|
40
Six months ended June 30, 2017 versus June 30, 2016
Natural gas revenues increased $159 million compared to the first six months of 2016 primarily due to:
|
●
|
|
Higher average realized natural gas prices of $1.10 per Mcf, or 71 percent, increased revenues by $236
million. The increase reflected higher NYMEX, AECO and Algonquin City Gate benchmark prices which were up 61 percent, 70 percent and 28 percent, respectively;
|
partially offset by:
|
●
|
|
Lower average natural gas production volumes of 272 MMcf/d decreased revenues by $77 million. Lower volumes
were primarily due to the sales of the Gordondale (79 MMcf/d) and DJ Basin assets (47 MMcf/d) in the third quarter of 2016, lower natural gas volumes in Montney due to natural declines and Encanas focus on liquids rich wells in the play (60
MMcf/d), natural declines in Other Upstream Operations (49 MMcf/d) and increased downtime resulting from scheduled third-party plant maintenance in Montney (36 MMcf/d).
|
Gains (Losses) on Risk Management, Net
As a means of managing commodity price volatility, Encana enters into commodity derivative financial instruments on a portion of its expected
oil, NGL and natural gas production volumes. The Companys commodity price mitigation program reduces volatility and helps sustain revenues during periods of lower prices. Further information on the Companys commodity price positions as
at June 30, 2017 can be found in Note 19 to the Consolidated Financial Statements included in Part I, Item 1 of this Quarterly Report on Form 10-Q.
The following table provides the effects of Encanas risk management activities on revenues.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30,
|
|
|
|
|
|
Six months ended June 30,
|
|
($ millions)
|
|
2017
|
|
|
2016
|
|
|
|
|
|
2017
|
|
|
2016
|
|
|
|
|
|
|
|
Realized Gains (Losses) on Risk Management
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity Price
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
$
|
16
|
|
|
$
|
58
|
|
|
|
|
|
|
$
|
16
|
|
|
$
|
172
|
|
NGLs
(1)
|
|
|
2
|
|
|
|
-
|
|
|
|
|
|
|
|
1
|
|
|
|
-
|
|
Natural Gas
|
|
|
-
|
|
|
|
66
|
|
|
|
|
|
|
|
(25)
|
|
|
|
128
|
|
Other
(2)
|
|
|
1
|
|
|
|
3
|
|
|
|
|
|
|
|
3
|
|
|
|
4
|
|
Total
|
|
|
19
|
|
|
|
127
|
|
|
|
|
|
|
|
(5)
|
|
|
|
304
|
|
|
|
|
|
|
|
Unrealized Gains (Losses) on Risk Management
|
|
|
110
|
|
|
|
(457)
|
|
|
|
|
|
|
|
472
|
|
|
|
(511)
|
|
Total Gains (Losses) on Risk Management, Net
|
|
$
|
129
|
|
|
$
|
(330)
|
|
|
|
|
|
|
$
|
467
|
|
|
$
|
(207)
|
|
|
|
|
|
|
|
Three months ended June 30,
|
|
|
|
|
|
Six months ended June 30,
|
|
(Per-unit)
|
|
2017
|
|
|
2016
|
|
|
|
|
|
2017
|
|
|
2016
|
|
|
|
|
|
|
|
Realized Gains (Losses) on Risk Management
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity Price
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil ($/bbl)
|
|
$
|
2.16
|
|
|
$
|
8.00
|
|
|
|
|
|
|
$
|
1.19
|
|
|
$
|
11.80
|
|
NGLs
(1)
($/bbl)
|
|
$
|
0.73
|
|
|
$
|
0.05
|
|
|
|
|
|
|
$
|
0.19
|
|
|
$
|
0.02
|
|
Natural Gas ($/Mcf)
|
|
$
|
(0.01)
|
|
|
$
|
0.51
|
|
|
|
|
|
|
$
|
(0.12)
|
|
|
$
|
0.48
|
|
Total ($/BOE)
|
|
$
|
0.62
|
|
|
$
|
3.69
|
|
|
|
|
|
|
$
|
(0.14)
|
|
|
$
|
4.38
|
|
|
(1)
|
Includes plant condensate.
|
|
(2)
|
Other primarily includes realized gains or losses from other derivative contracts with no associated production volumes.
|
Encana recognizes fair value changes from its risk management activities each reporting period. The changes in fair value result from new
positions and settlements that occur during each period, as well as the relationship between contract prices and the associated forward curves. Realized gains or losses on risk management activities related to commodity price mitigation are included
in the Canadian Operations, USA Operations and Market Optimization revenues as the contracts are cash settled. Unrealized gains or losses on fair value changes of unsettled contracts are included in the Corporate and Other segment.
41
Market Optimization Revenues
Market Optimization revenues relate to activities that provide operational flexibility and cost mitigation for transportation commitments,
product type, delivery points and customer diversification.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30,
|
|
|
|
|
|
Six months ended June 30,
|
|
($ millions)
|
|
2017
|
|
|
2016
|
|
|
|
|
|
2017
|
|
|
2016
|
|
|
|
|
|
|
|
Market Optimization
|
|
$
|
204
|
|
|
$
|
91
|
|
|
|
|
|
|
$
|
390
|
|
|
$
|
178
|
|
Three months ended June 30, 2017 versus June 30, 2016
Market Optimization revenues increased $113 million compared to the second quarter of 2016 primarily due to:
|
●
|
|
Higher commodity prices ($73 million) and higher sales of third-party purchased volumes used for optimization
activities ($40 million).
|
Six months ended June 30, 2017 versus June 30, 2016
Market Optimization revenues increased $212 million compared to the first six months of 2016 primarily due to:
|
●
|
|
Higher commodity prices ($127 million) and higher sales of third-party purchased volumes used for optimization
activities ($85 million).
|
Other Revenues
Other Revenues primarily includes amounts related to the sublease of office space in The Bow office building recorded in the Corporate and
Other segment, as well as third party transportation and processing revenues with no associated volumes recorded in the Canadian and USA Operations segments. Further information on The Bow office sublease can be found in Note 10 to the Consolidated
Financial Statements included in Part I, Item 1 of this Quarterly Report on Form 10-Q.
Operating Expenses
Production, Mineral and
Other Taxes
Production, mineral and other taxes include production and property taxes. Production taxes are generally assessed
as a percentage of oil and gas production revenues. Property taxes are generally assessed based on the value of the underlying assets.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30,
|
|
|
|
|
|
Six months ended June 30,
|
|
($ millions)
|
|
2017
|
|
|
2016
|
|
|
|
|
|
2017
|
|
|
2016
|
|
|
|
|
|
|
|
Canadian Operations
|
|
$
|
5
|
|
|
$
|
6
|
|
|
|
|
|
|
$
|
10
|
|
|
$
|
12
|
|
USA Operations
|
|
|
19
|
|
|
|
24
|
|
|
|
|
|
|
|
43
|
|
|
|
41
|
|
Total
|
|
$
|
24
|
|
|
$
|
30
|
|
|
|
|
|
|
$
|
53
|
|
|
$
|
53
|
|
|
|
|
|
|
|
Three months ended June 30,
|
|
|
|
|
|
Six months ended June 30,
|
|
($/BOE)
|
|
2017
|
|
|
2016
|
|
|
|
|
|
2017
|
|
|
2016
|
|
|
|
|
|
|
|
Canadian Operations
|
|
$
|
0.39
|
|
|
$
|
0.36
|
|
|
|
|
|
|
$
|
0.34
|
|
|
$
|
0.33
|
|
USA Operations
|
|
$
|
1.29
|
|
|
$
|
1.48
|
|
|
|
|
|
|
$
|
1.55
|
|
|
$
|
1.27
|
|
Total
|
|
$
|
0.85
|
|
|
$
|
0.89
|
|
|
|
|
|
|
$
|
0.93
|
|
|
$
|
0.77
|
|
42
Three months ended June 30, 2017 versus June 30, 2016
Production, mineral and other taxes decreased $6 million compared to the second quarter of 2016 primarily due to:
|
●
|
|
The recovery of certain production taxes in the USA Operations ($10 million) and the sales of the DJ Basin and
Gordondale assets in the third quarter of 2016 ($2 million);
|
partially offset by:
|
●
|
|
Higher commodity prices in the USA Operations and higher oil production volumes in Permian and Eagle Ford ($6
million).
|
Six months ended June 30, 2017 versus June 30, 2016
Production, mineral and other taxes were flat compared to the first six months of 2016 and were impacted by:
|
●
|
|
Higher commodity prices in the USA Operations and higher oil production volumes in Permian ($14 million);
|
partially offset by:
|
●
|
|
The recovery of certain production taxes in the USA Operations ($9 million) and the sales of the DJ Basin and
Gordondale assets in the third quarter of 2016 ($4 million).
|
Transportation and Processing
Transportation and processing expense includes transportation costs incurred to move product from production points to sales points including
gathering, compression, pipeline tariffs, trucking and storage costs. Encana also incurs costs related to processing provided by third parties or through ownership interests in processing facilities to bring raw production to sales-quality product.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30,
|
|
|
|
|
|
Six months ended June 30,
|
|
($ millions)
|
|
2017
|
|
|
2016
|
|
|
|
|
|
2017
|
|
|
2016
|
|
|
|
|
|
|
|
Canadian Operations
|
|
$
|
133
|
|
|
$
|
155
|
|
|
|
|
|
|
$
|
265
|
|
|
$
|
304
|
|
USA Operations
|
|
|
51
|
|
|
|
73
|
|
|
|
|
|
|
|
110
|
|
|
|
171
|
|
Upstream Transportation and Processing
|
|
|
184
|
|
|
|
228
|
|
|
|
|
|
|
|
375
|
|
|
|
475
|
|
|
|
|
|
|
|
Market Optimization
|
|
|
22
|
|
|
|
22
|
|
|
|
|
|
|
|
43
|
|
|
|
43
|
|
Corporate & Other
|
|
|
-
|
|
|
|
(6)
|
|
|
|
|
|
|
|
-
|
|
|
|
(5)
|
|
Total
|
|
$
|
206
|
|
|
$
|
244
|
|
|
|
|
|
|
$
|
418
|
|
|
$
|
513
|
|
|
|
|
|
|
|
Three months ended June 30,
|
|
|
|
|
|
Six months ended June 30,
|
|
($/BOE)
|
|
2017
|
|
|
2016
|
|
|
|
|
|
2017
|
|
|
2016
|
|
|
|
|
|
|
|
Canadian Operations
|
|
$
|
9.30
|
|
|
$
|
8.85
|
|
|
|
|
|
|
$
|
8.91
|
|
|
$
|
8.34
|
|
USA Operations
|
|
$
|
3.54
|
|
|
$
|
4.56
|
|
|
|
|
|
|
$
|
3.97
|
|
|
$
|
5.34
|
|
Upstream Transportation and Processing
|
|
$
|
6.39
|
|
|
$
|
6.80
|
|
|
|
|
|
|
$
|
6.53
|
|
|
$
|
6.94
|
|
Three months ended June 30, 2017 versus June 30, 2016
Transportation and processing expense decreased $38 million compared to the second quarter of 2016 primarily due to:
|
●
|
|
The sales of the Gordondale and DJ Basin assets in the third quarter of 2016 ($26 million), the renegotiation
and expiration of certain transportation contracts ($14 million), and the lower U.S./Canadian dollar exchange rate ($7 million);
|
partially offset by:
|
●
|
|
Higher volumes and prices in Permian ($6 million) and increased downstream processing costs in Montney due to
Encanas focus on liquids rich wells in the play ($3 million).
|
43
Six months ended June 30, 2017 versus June 30, 2016
Transportation and processing expense decreased $95 million compared to the first six months of 2016 primarily due to:
|
●
|
|
The sales of the Gordondale and DJ Basin assets in the third quarter of 2016 ($48 million), the renegotiation
and expiration of certain transportation contracts ($44 million) and lower gas gathering and processing fees in Montney, Duvernay and Other Upstream Operations ($17 million);
|
partially offset by:
|
●
|
|
Higher volumes and prices in Permian ($12 million) and increased downstream processing costs in Montney and
Duvernay due to Encanas focus on liquids rich wells in the plays ($8 million).
|
Operating
Operating expense includes costs paid by Encana to operate oil and gas properties in which the Company has a working interest. These costs
primarily include labour, service contract fees, chemicals and fuel.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30,
|
|
|
|
|
|
Six months ended June 30,
|
|
($ millions)
|
|
2017
|
|
|
2016
|
|
|
|
|
|
2017
|
|
|
2016
|
|
|
|
|
|
|
|
Canadian Operations
|
|
$
|
22
|
|
|
$
|
37
|
|
|
|
|
|
|
$
|
53
|
|
|
$
|
77
|
|
USA Operations
|
|
|
84
|
|
|
|
87
|
|
|
|
|
|
|
|
171
|
|
|
|
200
|
|
Upstream Operating Expense
|
|
|
106
|
|
|
|
124
|
|
|
|
|
|
|
|
224
|
|
|
|
277
|
|
|
|
|
|
|
|
Market Optimization
|
|
|
3
|
|
|
|
6
|
|
|
|
|
|
|
|
12
|
|
|
|
14
|
|
Corporate & Other
|
|
|
4
|
|
|
|
5
|
|
|
|
|
|
|
|
9
|
|
|
|
10
|
|
Total
|
|
$
|
113
|
|
|
$
|
135
|
|
|
|
|
|
|
$
|
245
|
|
|
$
|
301
|
|
|
|
|
|
|
|
Three months ended June 30,
|
|
|
|
|
|
Six months ended June 30,
|
|
($/BOE)
|
|
2017
|
|
|
2016
|
|
|
|
|
|
2017
|
|
|
2016
|
|
|
|
|
|
|
|
Canadian Operations
|
|
$
|
1.52
|
|
|
$
|
2.08
|
|
|
|
|
|
|
$
|
1.73
|
|
|
$
|
2.06
|
|
USA Operations
|
|
$
|
5.60
|
|
|
$
|
5.34
|
|
|
|
|
|
|
$
|
5.99
|
|
|
$
|
6.20
|
|
Upstream Operating Expense
(1)
|
|
$
|
3.58
|
|
|
$
|
3.63
|
|
|
|
|
|
|
$
|
3.78
|
|
|
$
|
4.00
|
|
|
(1)
|
Upstream Operating Expense per BOE for the second quarter and the first six months of 2017 includes a recovery of long-term incentive costs of $0.18/BOE and $0.01/BOE, respectively (2016 long-term incentive costs
of $0.27/BOE and $0.15/BOE, respectively).
|
Three months ended June 30, 2017 versus June 30, 2016
Operating expense decreased $22 million compared to the second quarter of 2016 primarily due to:
|
●
|
|
Lower long-term incentive costs resulting from the decrease in Encanas share price in the second quarter
of 2017 ($19 million), asset sales which primarily included the sales of the DJ Basin and Gordondale assets in the third quarter of 2016 ($12 million), lower salaries and benefits due to a lower headcount ($8 million) and cost-savings
initiatives ($4 million);
|
partially offset by:
|
●
|
|
Higher activity in Permian and Eagle Ford ($17 million).
|
44
Six months ended June 30, 2017 versus June 30, 2016
Operating expense decreased $56 million compared to the first six months of 2016 primarily due to:
|
●
|
|
Asset sales which primarily included the sales of the DJ Basin and Gordondale assets in the third quarter of
2016 ($21 million), cost-saving initiatives ($20 million), lower salaries and benefits due to a lower headcount ($18 million) and lower long-term incentive costs resulting from the decrease in Encanas share price in the first six months of
2017 ($13 million);
|
partially offset by:
|
●
|
|
Higher activity in Permian and Eagle Ford ($18 million).
|
Further information on Encanas long-term incentives can be found in Note 16 to the Consolidated Financial Statements included in Part I,
Item 1 of this Quarterly Report on Form 10-Q.
Purchased Product
Purchased product expense includes purchases of oil, NGL and natural gas from third parties that are used to provide operational flexibility
and cost mitigation for transportation commitments, product type, delivery points and customer diversification.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30,
|
|
|
|
|
|
Six months ended June 30,
|
|
($ millions)
|
|
2017
|
|
|
2016
|
|
|
|
|
|
2017
|
|
|
2016
|
|
|
|
|
|
|
|
Market Optimization
|
|
$
|
192
|
|
|
$
|
79
|
|
|
|
|
|
|
$
|
363
|
|
|
$
|
152
|
|
Three months ended June 30, 2017 versus June 30, 2016
Purchased product expense increased $113 million compared to the second quarter of 2016 primarily due to:
|
●
|
|
Higher commodity prices ($70 million) and higher third-party volumes purchased for optimization activities
($43 million).
|
Six months ended June 30, 2017 versus June 30, 2016
Purchased product expense increased $211 million compared to the first six months of 2016 primarily due to:
|
●
|
|
Higher commodity prices ($122 million) and higher third-party volumes purchased for optimization activities
($89 million).
|
45
Depreciation, Depletion & Amortization
Proved properties within each country cost centre are depleted using the unit-of-production method based on proved reserves as discussed in
Note 1 to the Consolidated Financial Statements included in Item 8 of the 2016 Annual Report on Form 10-K. Depletion rates are impacted by impairments, acquisitions, divestitures and foreign exchange rates as well as fluctuations in 12-month
average trailing prices which affect proved reserves volumes. For additional information on Critical Accounting Estimates, refer to the MD&A included in Item 7 of the 2016 Annual Report on Form 10-K. Corporate assets are carried at cost and
depreciated on a straight-line basis over the estimated service lives of the assets.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30,
|
|
|
|
|
|
Six months ended June 30,
|
|
($ millions)
|
|
2017
|
|
|
2016
|
|
|
|
|
|
2017
|
|
|
2016
|
|
|
|
|
|
|
|
Canadian Operations
|
|
$
|
53
|
|
|
$
|
67
|
|
|
|
|
|
|
$
|
117
|
|
|
$
|
149
|
|
USA Operations
|
|
|
123
|
|
|
|
143
|
|
|
|
|
|
|
|
229
|
|
|
|
302
|
|
Upstream DD&A
|
|
|
176
|
|
|
|
210
|
|
|
|
|
|
|
|
346
|
|
|
|
451
|
|
|
|
|
|
|
|
Corporate & Other
|
|
|
17
|
|
|
|
20
|
|
|
|
|
|
|
|
34
|
|
|
|
40
|
|
Total
|
|
$
|
193
|
|
|
$
|
230
|
|
|
|
|
|
|
$
|
380
|
|
|
$
|
491
|
|
|
|
|
|
|
|
Three months ended June 30,
|
|
|
|
|
|
Six months ended June 30,
|
|
($/BOE)
|
|
2017
|
|
|
2016
|
|
|
|
|
|
2017
|
|
|
2016
|
|
|
|
|
|
|
|
Canadian Operations
|
|
$
|
3.72
|
|
|
$
|
3.87
|
|
|
|
|
|
|
$
|
3.92
|
|
|
$
|
4.10
|
|
USA Operations
|
|
$
|
8.47
|
|
|
$
|
8.90
|
|
|
|
|
|
|
$
|
8.29
|
|
|
$
|
9.44
|
|
Upstream DD&A
|
|
$
|
6.12
|
|
|
$
|
6.28
|
|
|
|
|
|
|
$
|
6.02
|
|
|
$
|
6.60
|
|
Three months ended June 30, 2017 versus June 30, 2016
DD&A decreased $37 million compared to the second quarter of 2016 primarily due to:
|
●
|
|
Lower production volumes ($22 million) and depletion rates ($9 million) in the Canadian and USA Operations.
|
The depletion rate decreased $0.16 per BOE compared to the second quarter of 2016 primarily due to:
|
●
|
|
Ceiling test impairments recognized in the first six months of 2016 in the Canadian and USA Operations and the
sale of the DJ Basin assets in the third quarter of 2016.
|
Six months ended June 30, 2017 versus
June 30, 2016
DD&A decreased $111 million compared to the first six months of 2016 primarily due to:
|
●
|
|
Lower production volumes ($64 million) and depletion rates ($42 million) in the Canadian and USA Operations.
|
The depletion rate decreased $0.58 per BOE compared to the first six months of 2016 primarily due to:
|
●
|
|
Ceiling test impairments recognized in the first six months of 2016 in the Canadian and USA Operations and the
sale of the DJ Basin assets in the third quarter of 2016.
|
46
Impairments
Under full cost accounting, the carrying amount of Encanas oil and natural gas properties within each country cost centre is subject to
a ceiling test at the end of each quarter. Ceiling test impairments are recognized when the capitalized costs, net of accumulated depletion and the related deferred income taxes, exceed the sum of the estimated after-tax future net cash flows from
proved reserves as calculated under SEC requirements using the 12-month average trailing prices and discounted at 10 percent.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30,
|
|
|
|
|
|
Six months ended June 30,
|
|
($ millions)
|
|
2017
|
|
|
2016
|
|
|
|
|
|
2017
|
|
|
2016
|
|
|
|
|
|
|
|
Canadian Operations
|
|
$
|
-
|
|
|
$
|
226
|
|
|
|
|
|
|
$
|
-
|
|
|
$
|
493
|
|
USA Operations
|
|
|
-
|
|
|
|
258
|
|
|
|
|
|
|
|
-
|
|
|
|
903
|
|
Total
|
|
$
|
-
|
|
|
$
|
484
|
|
|
|
|
|
|
$
|
-
|
|
|
$
|
1,396
|
|
Ceiling test impairments in the second quarter and first six months of 2016 were primarily due to the decline
in the 12-month average trailing prices, which reduced the Canadian and 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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil & NGLs
|
|
|
|
|
|
Natural
Gas
|
|
|
|
WTI
($/bbl)
|
|
|
Edmonton
Condensate
(2)
(C$/bbl)
|
|
|
|
|
|
Henry Hub
($/MMBtu)
|
|
|
AECO
(C$/MMBtu)
|
|
|
|
|
|
|
|
12-Month Average Trailing Reserves Pricing
(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2017
|
|
|
48.95
|
|
|
|
64.27
|
|
|
|
|
|
|
|
3.01
|
|
|
|
2.76
|
|
December 31, 2016
|
|
|
42.75
|
|
|
|
55.39
|
|
|
|
|
|
|
|
2.49
|
|
|
|
2.17
|
|
June 30, 2016
|
|
|
43.12
|
|
|
|
55.63
|
|
|
|
|
|
|
|
2.24
|
|
|
|
2.14
|
|
|
(1)
|
All prices were held constant in all future years when estimating net revenues and reserves.
|
|
(2)
|
Edmonton Condensate benchmark price has replaced the previously disclosed Edmonton Light Sweet benchmark price.
|
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 oil and natural gas 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 liquids and natural gas 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. Additional information on the ceiling test calculation can be found in the Critical Accounting Estimates section of the MD&A included in Item 7 of the 2016 Annual
Report on Form 10-K.
Administrative
Administrative expense represents costs associated with corporate functions provided by Encana staff in the Calgary and Denver offices. Costs
primarily include salaries and benefits, general office, information technology, restructuring and long-term incentive costs.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30,
|
|
|
|
|
|
Six months ended June 30,
|
|
|
|
2017
|
|
|
2016
|
|
|
|
|
|
2017
|
|
|
2016
|
|
|
|
|
|
|
|
Administrative ($ millions)
|
|
$
|
24
|
|
|
$
|
61
|
|
|
|
|
|
|
$
|
82
|
|
|
$
|
140
|
|
Administrative ($/BOE)
|
|
$
|
0.82
|
|
|
$
|
1.82
|
|
|
|
|
|
|
$
|
1.43
|
|
|
$
|
2.05
|
|
47
Administrative expense in the second quarter of 2017 decreased $37 million from 2016 primarily
due to lower long-term incentive costs resulting from the decrease in Encanas share price in the second quarter of 2017 ($40 million). Administrative expense per BOE for the second quarter of 2017 includes a recovery of long-term incentive
costs of $0.79/BOE compared to long-term incentive costs of $0.55/BOE in 2016.
Administrative expense in the first six months of 2017
decreased $58 million from 2016 primarily due to lower restructuring costs ($31 million) and lower long-term incentive costs resulting from the decrease in Encanas share price in the first six months of 2017 ($30 million). Administrative
expense per BOE for the first six months of 2017 includes a recovery of long-term incentive costs of $0.13/BOE compared to long-term incentive costs and restructuring costs of $0.34/BOE and $0.46/BOE, respectively, in 2016.
During the first quarter of 2016, Encana completed workforce reductions announced in February 2016 to better align staffing levels and the
organizational structure with its reduced capital spending program as a result of the low commodity price environment. Encana incurred restructuring costs of $31 million during the first six months of 2016. There were no restructuring costs in the
first six months of 2017. Further information on restructuring costs can be found in Note 15 to the Consolidated Financial Statements included in Part I, Item 1 of this Quarterly Report on Form 10-Q.
Other (Income) Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30,
|
|
|
|
|
|
Six months ended June 30,
|
|
($ millions)
|
|
2017
|
|
|
2016
|
|
|
|
|
|
2017
|
|
|
2016
|
|
|
|
|
|
|
|
Interest
|
|
$
|
79
|
|
|
$
|
107
|
|
|
|
|
|
|
$
|
167
|
|
|
$
|
210
|
|
|
|
|
|
|
|
Foreign exchange (gain) loss, net
|
|
|
(58)
|
|
|
|
23
|
|
|
|
|
|
|
|
(84)
|
|
|
|
(356)
|
|
|
|
|
|
|
|
(Gain) loss on divestitures, net
|
|
|
-
|
|
|
|
2
|
|
|
|
|
|
|
|
1
|
|
|
|
2
|
|
|
|
|
|
|
|
Other (gains) losses, net
|
|
|
(27)
|
|
|
|
24
|
|
|
|
|
|
|
|
(35)
|
|
|
|
(63)
|
|
|
|
|
|
|
|
Total Other (Income) Expenses
|
|
$
|
(6)
|
|
|
$
|
156
|
|
|
|
|
|
|
$
|
49
|
|
|
$
|
(207)
|
|
Interest
Interest expense primarily includes interest on Encanas long-term debt arising from U.S. dollar denominated unsecured notes and balances
drawn on the Companys credit facilities. Encana also incurs interest on the Companys long-term obligation for The Bow office building and capital leases.
Interest expense in the second quarter of 2017 decreased $28 million compared to 2016 primarily due to a recovery of other interest in the
second quarter of 2017 compared to other interest expense in 2016 ($17 million) and lower interest on debt ($9 million).
Interest expense
in the first six months of 2017 decreased $43 million compared to 2016 primarily due to lower interest on debt ($24 million) and a recovery of other interest in 2017 compared to other interest expense in 2016 ($17 million).
The recovery of other interest in the second quarter and first six months of 2017 is primarily due to the successful resolution of certain tax
items previously assessed by the tax authorities relating to prior taxation years. Lower interest on debt in the second quarter and first six months of 2017 is primarily due to the early retirement of long-term debt in March 2016. Further
information on the March 2016 debt retirement can be found in the Liquidity and Capital Resources section of this MD&A.
48
Foreign Exchange (Gain) Loss, Net
Foreign exchange gains and losses result from the impact of fluctuations in the Canadian to U.S. dollar exchange rate. In the second quarter
and first six months of 2017, the average U.S./Canadian dollar foreign exchange rate was 0.744 and 0.750, respectively, compared to 0.776 and 0.752, respectively for 2016. The period end U.S./Canadian dollar foreign exchange rates as at
June 30, 2017 and December 31, 2016 were 0.771 and 0.745, respectively.
In the second quarter of 2017, Encana recorded
unrealized foreign exchange gains on the translation of U.S. dollar financing debt issued from Canada compared to foreign exchange losses in 2016 ($104 million), which includes an out-of-period adjustment of $68 million, before tax, in respect of
cumulative unrealized losses on a foreign-denominated capital lease obligation since December 2013. Encana also recorded higher unrealized foreign exchange gains on the translation of U.S. dollar risk management contracts issued from Canada compared
to 2016 ($28 million), partially offset by foreign exchange losses on the settlement of U.S. dollar financing debt issued from Canada compared to foreign exchange gains in the second quarter of 2016 ($48 million).
In the first six months of 2017, Encana recorded lower unrealized foreign exchange gains on the translation of U.S. dollar financing debt
issued from Canada compared to 2016 ($199 million), which includes an out-of-period adjustment of $68 million as discussed above. Encana also recorded foreign exchange losses on the settlement of U.S. dollar financing debt issued from Canada
compared to foreign exchange gains in the first six months of 2016 ($79 million), partially offset by unrealized foreign exchange gains on the translation of U.S. dollar risk management contracts issued from Canada compared to foreign exchange
losses in the first six months of 2016 ($38 million).
Further information on the out-of-period adjustment can be found in Note 6 to the
Consolidated Financial Statements included in Part I, Item 1 of this Quarterly Report on Form 10-Q.
Other (Gains) Losses,
Net
Other (gains) losses, net primarily includes other non-recurring revenues or expenses and may also include items such as
interest income on short-term investments, interest received from tax authorities, reclamation charges relating to decommissioned assets and earnings/losses from equity investments.
Other gains in the second quarter and first six months of 2017 primarily includes interest received of $26 million and $33 million,
respectively, resulting from the successful resolution of certain tax items previously assessed by the tax authorities relating to prior taxation years.
Other gains in the first six months of 2016 primarily includes a gain of $89 million on the early retirement of long-term debt as discussed in
the Liquidity and Capital Resources section of this MD&A, partially offset by a one-time third party payment relating to a previously divested asset.
49
Income Tax
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30,
|
|
|
|
|
Six months ended June 30,
|
|
($ millions)
|
|
2017
|
|
|
2016
|
|
|
|
|
2017
|
|
|
2016
|
|
|
|
|
|
|
|
Current Income Tax Expense (Recovery)
|
|
$
|
(18)
|
|
|
$
|
(12)
|
|
|
|
|
$
|
(57)
|
|
|
$
|
(9)
|
|
|
|
|
|
|
|
Deferred Income Tax Expense (Recovery)
|
|
|
14
|
|
|
|
(455)
|
|
|
|
|
|
56
|
|
|
|
(759)
|
|
|
|
|
|
|
|
Income Tax Expense (Recovery)
|
|
$
|
(4)
|
|
|
$
|
(467)
|
|
|
|
|
$
|
(1)
|
|
|
$
|
(768)
|
|
|
|
|
|
|
|
Effective Tax Rate
|
|
|
(1.2%)
|
|
|
|
43.7%
|
|
|
|
|
|
(0.1%)
|
|
|
|
43.9%
|
|
Income Tax Expense (Recovery)
Three months ended June 30, 2017 versus June 30, 2016
In the second quarter of 2017, Encana recorded a lower income tax recovery compared to 2016. The lower income tax recovery was primarily due
to operating income in 2017 compared to an operating loss in 2016.
The current income tax recovery in the second quarter of 2017 was
primarily due to the successful resolution of certain tax items previously assessed by the tax authorities relating to prior taxation years.
The deferred tax recovery in the second quarter of 2016 was primarily due to the recognition of ceiling test impairments.
Six months ended June 30, 2017 versus June 30, 2016
In the first six months of 2017, Encana recorded a lower income tax recovery compared to 2016. The lower income tax recovery was primarily due
to operating income in 2017 compared to an operating loss in 2016 and lower foreign exchange gains.
The current income tax recovery in
the first six months of 2017 was primarily due to the successful resolution of certain tax items previously assessed by the tax authorities relating to prior taxation years.
The deferred tax recovery in the first six months of 2016 was primarily due to the recognition of ceiling test impairments.
Effective Tax Rate
Encanas interim income tax expense is determined using the estimated annual effective income tax rate applied to year-to-date net
earnings before income tax plus the effect of legislative changes and amounts in respect of prior periods. The estimated annual effective income tax rate is impacted by expected annual earnings, income tax related to foreign operations, non-taxable
capital gains and losses, tax differences on divestitures and transactions, and partnership tax allocations in excess of funding. These items, along with the tax reassessments discussed above, resulted in an effective tax rate for the second quarter
and first six months of 2017 that is lower than the Canadian statutory rate of 27 percent. The effective tax rate for the second quarter and first six months of 2016 exceeded the Canadian statutory tax rate of 27 percent primarily due to the impact
of the foreign jurisdictional tax rates relative to the Canadian statutory tax rate applied to jurisdictional earnings.
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 for which the timing of resolution is uncertain. The
Company believes that the provision for income taxes is adequate.
50
|
Liquidity and Capital Resources
|
Sources of Liquidity
The Company has the flexibility to
access cash equivalents and a range of funding alternatives at competitive rates through committed revolving bank credit facilities as well as debt and equity capital markets. Encana closely monitors the accessibility of cost-effective credit and
ensures that sufficient liquidity is in place to fund capital expenditures and dividend payments. In addition, the Company may use cash and cash equivalents, cash from operating activities, or proceeds from asset divestitures and share issuances to
fund its operations and service debt repayments. At June 30, 2017, $158 million in cash and cash equivalents was held by U.S. subsidiaries. The cash held by U.S. subsidiaries is accessible and may be subject to additional Canadian income taxes
and U.S. withholding taxes if repatriated.
The Companys capital structure consists of total shareholders equity plus
long-term debt, including the current portion. The Companys objectives when managing its capital structure are to maintain financial flexibility to preserve Encanas access to capital markets and its ability to meet financial obligations
and finance internally generated growth, as well as potential acquisitions. Encana has a long-standing practice of maintaining capital discipline and strategically managing its capital structure by adjusting capital spending, adjusting dividends
paid to shareholders, issuing new shares, issuing new debt or repaying existing debt.
|
|
|
|
|
|
|
|
|
|
|
As at June 30,
|
|
($ millions, except as indicated)
|
|
2017
|
|
|
2016
|
|
|
|
|
Cash and Cash Equivalents
|
|
$
|
395
|
|
|
$
|
293
|
|
|
|
|
Available Credit Facility Encana
(1)
|
|
|
3,000
|
|
|
|
1,507
|
|
|
|
|
Available Credit Facility U.S. Subsidiary
(1)
|
|
|
1,500
|
|
|
|
1,500
|
|
Total Liquidity
|
|
|
4,895
|
|
|
|
3,300
|
|
|
|
|
Long-Term Debt
|
|
|
4,198
|
|
|
|
5,690
|
|
|
|
|
Total Shareholders Equity
|
|
|
6,783
|
|
|
|
4,907
|
|
|
|
|
Debt to Capitalization (%)
(2)
|
|
|
38
|
|
|
|
54
|
|
|
|
|
Debt to Adjusted Capitalization (%)
(3)
|
|
|
22
|
|
|
|
31
|
|
|
(1)
|
Collectively, the Credit Facilities.
|
|
(2)
|
Calculated as long-term debt, including the current portion, divided by shareholders equity plus long-term debt, including the current portion.
|
|
(3)
|
A non-GAAP measure which is defined in the Non-GAAP Measures section of this MD&A.
|
Encana
is currently in compliance with, and expects that it will continue to be in compliance with, all financial covenants under the Credit Facilities. Management monitors Debt to Adjusted Capitalization, which is a non-GAAP measure defined in the
Non-GAAP Measures section of this MD&A, as a proxy for Encanas financial covenant under the Credit Facilities, which requires 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. As shown in the table
above, Debt to Adjusted Capitalization as at June 30, 2017 decreased compared to 2016 as a result of Encanas efforts to strengthen its balance sheet through debt repayments. Additional information on financial covenants can be found in
Note 13 to the Consolidated Financial Statements included in Item 8 of the 2016 Annual Report on Form 10-K.
51
Sources and Uses of Cash
In the second quarter and first
six months of 2017, Encana primarily generated cash through operating activities. The following table summarizes the sources and uses of the Companys cash and cash equivalents.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30,
|
|
|
|
|
|
Six months ended June 30,
|
|
($ millions)
|
|
Activity Type
|
|
|
2017
|
|
|
2016
|
|
|
|
|
|
2017
|
|
|
2016
|
|
|
|
|
|
|
|
|
Sources of Cash and Cash Equivalents
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash from operating activities
|
|
|
Operating
|
|
|
$
|
218
|
|
|
$
|
83
|
|
|
|
|
|
|
$
|
324
|
|
|
$
|
240
|
|
Proceeds from divestitures
|
|
|
Investing
|
|
|
|
82
|
|
|
|
-
|
|
|
|
|
|
|
|
85
|
|
|
|
6
|
|
Net issuance of revolving long-term debt
|
|
|
Financing
|
|
|
|
-
|
|
|
|
288
|
|
|
|
|
|
|
|
-
|
|
|
|
843
|
|
Other
|
|
|
Investing
|
|
|
|
24
|
|
|
|
-
|
|
|
|
|
|
|
|
79
|
|
|
|
-
|
|
|
|
|
|
|
|
|
324
|
|
|
|
371
|
|
|
|
|
|
|
|
488
|
|
|
|
1,089
|
|
|
|
|
|
|
|
|
Uses of Cash and Cash Equivalents
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
|
Investing
|
|
|
|
415
|
|
|
|
215
|
|
|
|
|
|
|
|
814
|
|
|
|
574
|
|
Acquisitions
|
|
|
Investing
|
|
|
|
2
|
|
|
|
1
|
|
|
|
|
|
|
|
48
|
|
|
|
2
|
|
Repayment of long-term debt
|
|
|
Financing
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
-
|
|
|
|
400
|
|
Dividends on common shares
|
|
|
Financing
|
|
|
|
14
|
|
|
|
11
|
|
|
|
|
|
|
|
29
|
|
|
|
24
|
|
Other
|
|
|
Investing/Financing
|
|
|
|
24
|
|
|
|
73
|
|
|
|
|
|
|
|
40
|
|
|
|
76
|
|
|
|
|
|
|
|
|
455
|
|
|
|
300
|
|
|
|
|
|
|
|
931
|
|
|
|
1,076
|
|
|
|
|
|
|
|
|
Foreign Exchange Gain (Loss) on Cash and
Cash
Equivalents Held in Foreign Currency
|
|
|
|
|
|
|
3
|
|
|
|
-
|
|
|
|
|
|
|
|
4
|
|
|
|
9
|
|
Increase (Decrease) in Cash and Cash
Equivalents
|
|
|
$
|
(128)
|
|
|
$
|
71
|
|
|
|
|
|
|
$
|
(439)
|
|
|
$
|
22
|
|
Operating Activities
Cash from operating activities can be significantly impacted by fluctuations in commodity prices, operating costs, and changes in production
volumes. In the first six months of 2017, cash from operating activities was primarily impacted by recovering commodity prices, the Companys efforts in maintaining cost efficiencies achieved in 2016, a current tax recovery and interest
relating to the successful resolution of certain tax items previously assessed by the tax authorities and changes in non-cash working capital. Additional detail on changes in non-cash working capital can be found in Note 20 to the Consolidated
Financial Statements included in Part I, Item 1 of this Quarterly Report on Form 10-Q. Encana expects it will continue to meet the payment terms of its suppliers.
Non-GAAP Cash Flow in the second quarter and first six months of 2017 was $351 million and $629 million, respectively. Non-GAAP Cash Flow was
primarily impacted by the items affecting cash from operating activities which are discussed below and in the Results of Operations section of this MD&A. Non-GAAP Cash Flow excludes changes in non-cash working capital as disclosed in the
Non-GAAP Measures section of this MD&A.
Three months ended June 30, 2017 versus June 30, 2016
Net cash from operating activities in the second quarter of 2017 increased $135 million from the second quarter of 2016 primarily due to:
|
●
|
|
Higher realized commodity prices ($197 million), lower transportation and processing expense ($38 million),
higher interest income recorded in other gains ($27 million) and lower interest on long-term debt and other ($26 million);
|
partially offset by:
|
●
|
|
Lower realized gains on risk management included in revenues ($108 million), lower production volumes ($47
million) and changes in non-cash working capital ($35 million).
|
52
Six months ended June 30, 2017 versus June 30, 2016
Net cash from operating activities in the first six months of 2017 increased $84 million from the first six months of 2016 primarily due to:
|
●
|
|
Higher realized commodity prices ($516 million), lower transportation and processing expense ($95 million), a
higher current tax recovery ($48 million), lower interest on long-term debt and other ($41 million), lower operating expense, excluding non-cash long-term incentive costs ($38 million), higher interest income recorded in other gains
($35 million) and lower restructuring costs ($31 million);
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partially offset by:
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●
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Realized losses on risk management included in revenues in the first six months of 2017 compared to realized
gains in 2016 ($309 million), lower production volumes ($147 million) and changes in non-cash working capital ($254 million).
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Investing Activities
Net cash used in investing activities in the first six months of 2017 was $698
million primarily due to capital expenditures. Capital expenditures in the first six months of 2017 increased $240 million compared to 2016 due to an increase in the capital program for 2017. Capital expenditures in the Core Assets totaled $783
million, representing 96 percent of total capital expenditures, and increased $236 million compared to 2016, primarily in Permian ($109 million), Eagle Ford ($75 million) and Montney ($60 million). Capital expenditures exceeded cash from operating
activities by $490 million and the difference was funded using cash on hand.
Divestitures in the first six months of 2017 were $85
million, which primarily included the sale of the Tuscaloosa Marine Shale assets in Mississippi and Louisiana, as well as the sale of certain properties that did not complement Encanas existing portfolio of assets.
Acquisitions in the first six months of 2017 were $48 million, which primarily included land purchases with oil and liquids rich potential.
Capital expenditures and acquisition and divestiture activity are summarized in Notes 3 and 4 to the Consolidated Financial Statements
included in Part I, Item 1 of this Quarterly Report on Form 10-Q.
Financing Activities
Net cash used in financing activities in the first six months of 2017 was $69 million compared to net cash from financing activities of $387
million in 2016. The change was primarily due to a net issuance of revolving long-term debt ($843 million), partially offset by the repayment of long-term debt ($400 million), in the first six months of 2016.
Encanas long-term debt totaled $4,198 million at June 30, 2017 and December 31, 2016. There was no current portion outstanding
at June 30, 2017 or December 31, 2016. At June 30, 2017, Encana has no long-term debt maturities until 2019 and over 73 percent of the Companys debt is not due until 2030 and beyond.
In March 2016, the Company completed tender offers (collectively, the Tender Offers) for certain of the Companys outstanding
senior notes (collectively, the Notes) and accepted for purchase $489 million aggregate principal amount of Notes. The Company paid an aggregate amount of $406 million, including accrued and unpaid interest of $6 million and an early
tender premium of $14 million, which resulted in the recognition of a net gain on the early debt retirement of $89 million, before tax. The Company used cash on hand and borrowings under the Credit Facilities to fund the Tender Offers. Further
information on the Tender Offers can be found in Note 9 to the Consolidated Financial Statements included in Part I, Item 1 of this Quarterly Report on Form 10-Q.
The Company continues to have full access to the Credit Facilities, which remain committed through July 2020. The Credit Facilities provide
financial flexibility and allow the Company to fund its operations, development activities or capital program. At June 30, 2017, Encana had no outstanding balance under the Credit Facilities.
53
Dividends
Encana pays quarterly dividends to shareholders at the discretion of the Board of Directors.
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Three months ended June 30,
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Six months ended June 30,
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($ millions, except as indicated)
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2017
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2016
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2017
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2016
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Dividend Payments
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$
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14
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$
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12
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$
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29
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$
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25
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Dividend Payments ($/share)
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$
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0.015
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$
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0.015
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$
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0.03
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$
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0.03
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On July 20, 2017, the Board of Directors declared a dividend of $0.015 per common share payable on
September 29, 2017 to common shareholders of record as of September 15, 2017.
Off-Balance Sheet Arrangements
For information on off-balance sheet arrangements and transactions, refer to the Off-Balance Sheet Arrangements section of the
MD&A included in Item 7 of the 2016 Annual Report on Form 10-K.
Commitments and Contingencies
For information on commitments and contingencies, refer to Note 21 to the Consolidated Financial Statements included in Part I, Item 1 of
this Quarterly Report on Form 10-Q.
54
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 and should not be viewed as a substitute for measures reported under U.S. GAAP. 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: Non-GAAP
Cash Flow, Corporate Margin and Debt to Adjusted Capitalization. Managements use of these measures is discussed further below.
Non-GAAP Cash
Flow and Corporate Margin
Non-GAAP Cash Flow is a non-GAAP measure defined as cash from (used in) operating activities excluding net change in other assets and
liabilities, net change in non-cash working capital and current tax on sale of assets.
Corporate Margin is a non-GAAP measure defined as
Non-GAAP Cash Flow per BOE of production.
Management believes these measures are useful to the Company and its investors as a measure of
operating and financial performance across periods and against other companies in the industry, and are an indication of the Companys ability to generate cash to finance capital programs, to service debt and to meet other financial
obligations. These measures are used, along with other measures, in the calculation of certain performance targets for the Companys management and employees.
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Three months ended June 30,
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Six months ended June 30,
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($ millions, except as indicated)
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2017
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2016
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2017
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2016
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Cash From (Used in) Operating Activities
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$
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218
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$
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83
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$
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324
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$
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240
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(Add back) deduct:
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Net change in other assets and liabilities
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(4)
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(5)
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(16)
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(9)
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Net change in non-cash working capital
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(129)
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(94)
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(289)
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(35)
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Current tax on sale of assets
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-
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-
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-
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-
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Non-GAAP Cash Flow
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$
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351
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$
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182
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$
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629
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$
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284
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Production Volumes (MMBOE)
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28.8
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33.5
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57.4
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68.4
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Corporate Margin ($/BOE)
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$
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12.19
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$
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5.43
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$
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10.96
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$
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4.15
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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 the
Credit Facilities 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.
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($ millions, except as indicated)
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June 30, 2017
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December 31, 2016
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Debt
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$
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4,198
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$
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4,198
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Total Shareholders Equity
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6,783
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6,126
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Equity Adjustment for Impairments at December 31,
2011
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7,746
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7,746
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Adjusted Capitalization
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$
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18,727
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$
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18,070
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Debt to Adjusted Capitalization
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22%
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23%
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55