25.Supplementary Oil and Gas Information (unaudited)

The unaudited supplementary information on oil and gas exploration and production activities for 2017, 2016 and 2015 has been presented in accordance with the FASB’s ASC Topic 932, “Extractive Activities - Oil and Gas” and the SEC’s final rule, “Modernization of Oil and Gas Reporting”. Disclosures by geographic area include Canada and the United States.

Proved Oil and Gas Reserves

The following reserves disclosures reflect estimates of proved reserves, proved developed reserves, and proved undeveloped reserves, net of third-party royalty interests of oil, NGLs and natural gas owned at each year end and changes in proved reserves during each of the last three years.

The Company’s estimates of proved reserves are made using available geological and reservoir data as well as production performance data. These estimates are reviewed annually by internal reservoir engineers and revised, either upward or downward, as warranted by additional data. The results of infill drilling are treated as positive revisions due to increases to expected recovery. Other revisions are due to changes in, among other things, development plans, reservoir performance, commodity prices, economic conditions, and government restrictions. Estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors.

The following reference prices were utilized in the determination of reserves and future net revenue:



	Oil & NGLs		Natural Gas
	WTI ($/bbl)	Edmonton Condensate (2) (C$/bbl)	Henry Hub ($/MMBtu)	AECO (C$/MMBtu)

Reserves Pricing (1)
2017	51.34	67.65	2.98	2.32
2016	42.75	55.39	2.49	2.17
2015	50.28	61.94	2.58	2.69

(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.

PROVED RESERVES (1)

(12-MONTH AVERAGE TRAILING PRICES)


	Oil (MMbbls)			NGLs (MMbbls)			Natural Gas (Bcf)			Total (MMBOE)
	Canada	United States	Total	Canada	United States	Total	Canada	United States	Total
2015
Beginning of year	10.9	194.1	205.0	66.6	90.2	156.7	3,229	2,265	5,494	1,277.4
Revisions and improved recovery (2)	(0.9)	(73.6)	(74.6)	(14.8)	(41.1)	(55.9)	(801)	(342)	(1,144)	(321.1)
Extensions and discoveries	-	68.4	68.4	19.8	24.9	44.7	313	159	472	191.7
Purchase of reserves in place	-	-	-	-	-	-	-	-	-	-
Sale of reserves in place	(1.6)	(1.2)	(2.8)	(0.4)	(3.6)	(4.0)	(434)	(728)	(1,163)	(200.6)
Production	(2.0)	(29.7)	(31.8)	(8.3)	(8.6)	(16.9)	(354)	(241)	(596)	(148.0)
End of year	6.4	157.9	164.3	62.8	61.7	124.5	1,952	1,112	3,064	799.4
Developed	5.0	91.6	96.6	31.8	37.8	69.5	1,295	928	2,223	536.6
Undeveloped	1.3	66.3	67.7	31.0	24.0	55.0	657	184	841	262.8
Total	6.4	157.9	164.3	62.8	61.7	124.5	1,952	1,112	3,064	799.4

2016
Beginning of year	6.4	157.9	164.3	62.8	61.7	124.5	1,952	1,112	3,064	799.4
Revisions and improved recovery (2)	(0.3)	(15.6)	(15.9)	(6.4)	(1.6)	(8.0)	(422)	177	(244)	(64.7)
Extensions and discoveries	-	52.2	52.2	58.1	17.7	75.8	796	91	887	275.7
Purchase of reserves in place	-	9.6	9.6	-	2.6	2.6	-	16	16	14.9
Sale of reserves in place	(5.4)	(22.2)	(27.6)	(11.3)	(15.5)	(26.8)	(163)	(150)	(313)	(106.5)
Production	(0.7)	(26.2)	(27.0)	(9.2)	(8.5)	(17.7)	(354)	(153)	(506)	(129.1)
End of year	-	155.6	155.6	94.0	56.4	150.4	1,810	1,093	2,902	789.7
Developed	-	82.5	82.5	25.6	31.8	57.4	903	951	1,853	448.8
Undeveloped	-	73.1	73.1	68.4	24.6	93.0	907	142	1,049	341.0
Total	-	155.6	155.6	94.0	56.4	150.4	1,810	1,093	2,902	789.7

2017
Beginning of year	-	155.6	155.6	94.0	56.4	150.4	1,810	1,093	2,902	789.7
Revisions and improved recovery (2)	0.2	(16.0)	(15.8)	(14.6)	(3.6)	(18.1)	(31)	(27)	(58)	(43.6)
Extensions and discoveries	0.2	84.9	85.1	46.4	26.5	72.9	727	144	871	303.1
Purchase of reserves in place	-	0.8	0.8	-	0.4	0.4	-	2	2	1.5
Sale of reserves in place	-	(5.4)	(5.4)	(0.2)	(3.6)	(3.8)	(65)	(729)	(795)	(141.6)
Production	(0.2)	(27.7)	(27.8)	(10.6)	(8.7)	(19.3)	(306)	(97)	(403)	(114.3)
End of year	0.2	192.3	192.5	115.0	67.5	182.5	2,135	384	2,519	794.9
Developed	0.2	104.7	104.9	40.5	41.6	82.1	1,082	243	1,325	407.8
Undeveloped	-	87.7	87.7	74.5	25.8	100.3	1,053	141	1,195	387.1
Total	0.2	192.3	192.5	115.0	67.5	182.5	2,135	384	2,519	794.9

(1)

Numbers may not add due to rounding.

(2)

Changes in reserve estimates resulting from application of improved recovery techniques are nil and are included in revisions of previous estimates.

Definitions:

a. “Proved” oil and gas reserves are those quantities of oil and gas which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations.

b. “Developed” oil and gas reserves are reserves of any category that are expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well.

c. “Undeveloped” oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

Total Proved reserves increased 5.2 MMBOE in 2017 due to the following:

Revisions and improved recovery of oil, NGLs and natural gas were negative primarily due to negative revisions of 83.3 MMBOE resulting from changes in the approved development plan, which was partially offset by positive revisions of 32.6 MMBOE due to higher 12-month average trailing oil, NGL and natural gas prices.

Extensions and discoveries of oil, NGLs and natural gas increased proved reserves by 303.1 MMBOE due to the extension of proved acreage primarily from successful drilling in the Permian, Montney and Eagle Ford assets.

Sale of reserves in place decreased proved developed reserves by 141.6 MMBOE primarily due to the divestiture of the Piceance assets located in northwestern Colorado.

Total Proved reserves decreased 9.7 MMBOE in 2016 due to the following:

Revisions and improved recovery of oil and NGLs included reductions of 6.5 MMbbls and 6.6 MMbbls, respectively, due to lower 12-month average trailing oil and NGL prices. Revisions and improved recovery of natural gas included a reduction of 462 Bcf due to a lower 12-month average trailing natural gas price.

Extensions and discoveries of oil, NGLs and natural gas increased proved reserves by 275.7 MMBOE due to the extension of proved acreage primarily from successful drilling in the Permian and Montney assets.

Sale of reserves in place decreased proved developed reserves by 65.4 MMBOE and proved undeveloped reserves by 41.2 MMBOE due to the divestitures of the DJ Basin assets located in northern Colorado and the Gordondale assets located in northwestern Alberta.

Total Proved reserves decreased 478.0 MMBOE in 2015 due to the following:

Revisions and improved recovery of oil and NGLs included reductions of 59.9 MMbbls and 52.6 MMbbls, respectively, due to significantly lower 12-month average trailing oil and NGL prices. Revisions and improved recovery of natural gas included a reduction of 1,106 Bcf due to a significantly lower 12-month average trailing natural gas price.

Extensions and discoveries of oil, NGLs and natural gas increased proved reserves by 191.7 MMBOE due to the extension of proved acreage primarily from successful drilling in the Montney and Permian assets.

Sale of reserves in place decreased proved developed reserves by 137.4 MMBOE and proved undeveloped reserves by 63.2 MMBOE due to the divestitures of the Haynesville natural gas assets located in northern Louisiana and certain assets in Wheatland located in central and southern Alberta.

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES

In calculating the standardized measure of discounted future net cash flows, constant price and cost assumptions were applied to Encana’s annual future production from proved reserves to determine cash inflows. Estimates of future net cash flows from proved reserves are computed based on the average beginning-of-the-month prices during the 12-month period for the year. Future production and development costs include estimates for abandonment and dismantlement costs associated with asset retirement obligations and assume the continuation of existing economic, operating and regulatory conditions. Future income taxes are calculated by applying statutory income tax rates to future pre-tax cash flows after provision for the tax cost of the oil and natural gas properties based upon existing laws and regulations. The effect of tax credits is also considered in determining the income tax expense. The discount was computed by application of a 10 percent discount factor to the future net cash flows.

Encana cautions that the discounted future net cash flows relating to proved oil and gas reserves are an indication of neither the fair market value of Encana’s oil and gas properties, nor the future net cash flows expected to be generated from such properties. The discounted future net cash flows do not include the fair market value of exploratory properties and probable or possible oil and gas reserves, nor is consideration given to the effect of anticipated future changes in oil and natural gas prices, development, asset retirement and production costs, and possible changes to tax and royalty regulations. The prescribed discount rate of 10 percent may not appropriately reflect future interest rates.



	Canada (1)			United States (1)
	2017	2016	2015	2017	2016	2015

Future cash inflows	$ 7,850	$ 5,341	$ 6,284	$ 11,459	$ 8,537	$ 9,462
Less future:
Production costs	3,516	2,876	3,800	3,661	3,539	3,959
Development costs	2,058	1,949	1,742	3,042	2,805	3,130
Income taxes	76	-	-	-	-	-
Future net cash flows	2,200	516	742	4,756	2,193	2,373
Less 10% annual discount for estimated
timing of cash flows	618	77	107	2,025	957	960
Discounted future net cash flows	$ 1,582	$ 439	$ 635	$ 2,731	$ 1,236	$ 1,413



	Total (1)
	2017	2016	2015

Future cash inflows	$ 19,309	$ 13,878	$ 15,746
Less future:
Production costs	7,177	6,415	7,759
Development costs	5,100	4,754	4,872
Income taxes	76	-	-
Future net cash flows	6,956	2,709	3,115
Less 10% annual discount for estimated
timing of cash flows	2,643	1,034	1,067
Discounted future net cash flows	$ 4,313	$ 1,675	$ 2,048

(1) The standardized measure of future net cash flows relating to proved oil and gas reserves was amended to include estimated abandonment and reclamation

costs associated with proved undeveloped locations, which reduced the standardized measure by $13 million and $16 million in 2016 and 2015, respectively.

CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES



	Canada (1)			United States (1)
	2017	2016	2015	2017	2016	2015

Balance, beginning of year	$ 439	$ 635	$ 4,476	$ 1,236	$ 1,413	$ 7,074
Changes resulting from:
Sales of oil and gas produced during the year	(471)	(316)	(988)	(1,291)	(1,040)	(1,276)
Discoveries and extensions, net of related costs	582	211	109	1,141	267	504
Purchases of proved reserves in place	-	-	-	13	47	-
Sales and transfers of proved reserves in place	(12)	(71)	(674)	(413)	(220)	(1,604)
Net change in prices and production costs	893	20	(3,075)	2,183	325	(3,239)
Revisions to quantity estimates	(22)	(124)	(1,355)	(203)	39	(2,183)
Accretion of discount	44	64	565	124	141	833
Development costs incurred during the period	454	286	460	1,366	873	1,874
Changes in estimated future development costs	(279)	(304)	(13)	(1,433)	(456)	(1,809)
Other	7	38	(45)	8	(153)	(16)
Net change in income taxes	(53)	-	1,175	-	-	1,255
Balance, end of year	$ 1,582	$ 439	$ 635	$ 2,731	$ 1,236	$ 1,413



	Total (1)
	2017	2016	2015

Balance, beginning of year	$ 1,675	$ 2,048	$ 11,550
Changes resulting from:
Sales of oil and gas produced during the year	(1,762)	(1,356)	(2,264)
Discoveries and extensions, net of related costs	1,723	478	613
Purchases of proved reserves in place	13	47	-
Sales and transfers of proved reserves in place	(425)	(291)	(2,278)
Net change in prices and production costs	3,076	345	(6,314)
Revisions to quantity estimates	(225)	(85)	(3,538)
Accretion of discount	168	205	1,398
Development costs incurred during the period	1,820	1,159	2,334
Changes in estimated future development costs	(1,712)	(760)	(1,822)
Other	15	(115)	(61)
Net change in income taxes	(53)	-	2,430
Balance, end of year	$ 4,313	$ 1,675	$ 2,048

(1) The standardized measure of future net cash flows relating to proved oil and gas reserves was amended to include estimated abandonment and reclamation

costs associated with proved undeveloped locations, which reduced the standardized measure by $13 million, $16 million and $7 million in 2016, 2015 and 2014, respectively.

RESULTS OF OPERATIONS

The following table sets forth revenue and direct cost information relating to the Company’s oil and gas exploration and production activities.



	Canada			United States
	2017	2016	2015	2017	2016	2015

Oil, NGL and natural gas revenues, net of
transportation and processing	$ 613	$ 491	$ 1,168	$ 1,714	$ 1,510	$ 1,911
Less:
Operating costs, production, mineral and other taxes,
and accretion of asset retirement obligations	164	197	199	438	499	661
Depreciation, depletion and amortization	236	260	305	530	523	1,088
Impairments	-	493	-	-	903	6,473
Operating income (loss)	213	(459)	664	746	(415)	(6,311)
Income taxes	58	(123)	179	161	(150)	(2,285)
Results of operations	$ 155	$ (336)	$ 485	$ 585	$ (265)	$ (4,026)


	Total
	2017	2016	2015

Oil, NGL and natural gas revenues, net of
transportation and processing	$ 2,327	$ 2,001	$ 3,079
Less:
Operating costs, production, mineral and other taxes,
and accretion of asset retirement obligations	602	696	860
Depreciation, depletion and amortization	766	783	1,393
Impairments	-	1,396	6,473
Operating income (loss)	959	(874)	(5,647)
Income taxes	219	(273)	(2,106)
Results of operations	$ 740	$ (601)	$ (3,541)

CAPITALIZED COSTS

Capitalized costs include the cost of properties, equipment and facilities for oil and natural gas producing activities. Capitalized costs for proved properties include costs for oil and natural gas leaseholds where proved reserves have been identified, development wells and related equipment and facilities, including development wells in progress. Capitalized costs for unproved properties include costs for acquiring oil and gas leaseholds where no proved reserves have been identified.



	Canada			United States
	2017	2016	2015	2017	2016	2015

Proved oil and gas properties	$ 14,555	$ 13,159	$ 14,866	$ 25,610	$ 26,393	$ 25,723
Unproved oil and gas properties	311	285	334	4,169	4,913	5,282
Total capital cost	14,866	13,444	15,200	29,779	31,306	31,005
Accumulated DD&A	14,047	12,896	14,170	23,240	25,300	23,822
Net capitalized costs	$ 819	$ 548	$ 1,030	$ 6,539	$ 6,006	$ 7,183



	Other			Total
	2017	2016	2015	2017	2016	2015

Proved oil and gas properties	$ 63	$ 58	$ 58	$ 40,228	$ 39,610	$ 40,647
Unproved oil and gas properties	-	-	-	4,480	5,198	5,616
Total capital cost	63	58	58	44,708	44,808	46,263
Accumulated DD&A	63	58	58	37,350	38,254	38,050
Net capitalized costs	$ -	$ -	$ -	$ 7,358	$ 6,554	$ 8,213

COSTS INCURRED

Costs incurred includes both capitalized costs and costs charged to expense when incurred. Costs incurred also includes internal costs directly related to acquisition, exploration, and development activities, new asset retirement costs established in the current year as well as increases or decreases to the asset retirement obligations resulting from changes to cost estimates during the year.



	Canada			United States
	2017	2016	2015	2017	2016	2015

Acquisition costs
Unproved	$ 31	$ -	$ 2	$ 21	$ 4	$ 15
Proved	-	1	7	2	205	12
Total acquisition costs	31	1	9	23	209	27
Exploration costs	1	1	3	4	13	3
Development costs	425	255	377	1,354	860	1,844
Total costs incurred	$ 457	$ 257	$ 389	$ 1,381	$ 1,082	$ 1,874



	Total
	2017	2016	2015

Acquisition costs
Unproved	$ 52	$ 4	$ 17
Proved	2	206	19
Total acquisition costs	54	210	36
Exploration costs	5	14	6
Development costs	1,779	1,115	2,221
Total costs incurred	$ 1,838	$ 1,339	$ 2,263

COSTS NOT SUBJECT TO DEPLETION OR AMORTIZATION

Upstream costs in respect of significant unproved properties are excluded from the country cost centre’s depletable base as follows:




As at December 31		2017		2016

Canada	$	311	$	285
United States		4,169		4,913
	$	4,480	$	5,198

The following is a summary of the costs related to Encana’s unproved properties as at December 31, 2017:



		2017		2016		2015		Prior to 2015		Total

Acquisition Costs	$	245	$	104	$	29	$	3,965	$	4,343
Exploration Costs		2		5		8		122		137
	$	247	$	109	$	37	$	4,087	$	4,480

Acquisition costs primarily include costs incurred to acquire or lease properties. Exploration costs primarily include costs related to geological and geophysical studies and costs of drilling and equipping exploratory wells. Ultimate recoverability of these costs and the timing of inclusion within the applicable country cost centre’s depletable base is dependent upon either the finding of proved oil, NGL and natural gas reserves, expiration of leases or recognition of impairments.

Included in the $4.5 billion of oil and gas properties not subject to depletion or amortization are approximately $4.0 billion of acquired leasehold and mineral costs in the Permian related to the Company’s acquisition of Athlon Energy Inc. in 2014. These acquisition costs are associated with acquired acreage for which proved reserves have yet to be assigned from future development. The Company continually assesses the development timeline of the acquired acreage. The timing and amount of the transfer of property acquisition costs into the depletable base are based on several factors and may be subject to changes over time from drilling plans, drilling results, availability of capital, project economics and other assessments of the property. The inclusion of these acquisition costs in the depletable base is expected to occur within 8 to 12 years. The remaining costs excluded from depletion are related to properties which are not individually significant.