ECA Encana Corporation

 

 

U.S. SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 6-K

Report of Foreign Private Issuer

Pursuant to Rule 13a-16 or 15d-16

under the Securities Exchange Act of 1934

For August 6, 2015

Commission File Number: 1-15226

 

 

ENCANA CORPORATION

(Translation of registrant’s name into English)

Suite 4400, 500 Centre Street SE

PO Box 2850

Calgary, Alberta, Canada T2P 2S5

(Address of principal executive office)

 

 

Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F:

Form 20-F  ¨            Form 40-F  þ

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1):  ¨

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7):  ¨

 

 

 

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DOCUMENTS FILED AS PART OF THIS FORM 6-K

See the Exhibit Index to this Form 6-K.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Date: August 6, 2015

 

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Form 6-K Exhibit Index

 

Exhibit No.
99.1		Interim Report to Shareholders for the period ended June 30, 2015, including the Unaudited Interim Condensed Consolidated Financial Statements and Management’s Discussion and Analysis for the said period.

2015 Q2 Report
For the period ended June 30, 2015

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Q2 Report  |  For the period ended June 30, 2015

 

Encana delivers better wells, lower costs and increased well inventory

Strong operational performance in second quarter positions Encana for accelerated growth

 

 

 

 

		Encana Corporation

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Q2 Report  |  For the period ended June 30, 2015

 

Operational highlights: Lowering costs, improving well performance and increasing well inventory

 

 

 

 

Encana Corporation

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Q2 Report  |  For the period ended June 30, 2015

 

 

SECOND QUARTER HIGHLIGHTS

 

Financial Summary
(for the period ended June 30) ($ millions, except per share amounts)			Q2   2015				Q2     2014
Cash flow1			181				656
Per share diluted			0.22				0.89
Operating earnings (loss) 1			(167)				171
Per share diluted			(0.20)				0.23
Earnings Reconciliation Summary
Net earnings (loss) attributable to common shareholders			(1,610)				271
After-tax (addition) deduction:
Unrealized hedging gain (loss)			(187)				8
Impairments			(1,328)				-
Restructuring charges			(10)				(5)
Non-operating foreign exchange gain (loss)			114				156
Gain (loss) on divestitures			1				135
Income tax adjustments			(33)				(194)
Operating earnings (loss)1			(167)				171
Per share diluted			(0.20)				0.23

¹ Cash flow and operating earnings (loss) are non-GAAP measures as defined in Note 1 on page 5.

 

Production Summary
(for the period ended June 30)     (After royalties)			Q2   2015				Q2   2014				% D
Natural gas (MMcf/d)			1,568				2,541				(38)
Liquids (Mbbls/d)			127.3				68.2				87

 

Natural Gas and Liquids Prices
			Q2 2015				Q2 2014
Natural Gas
NYMEX ($/MMBtu)			2.64				4.67
Encana realized gas price1 ($/Mcf)			3.52				4.08
Oil and Natural Gas Liquids ($/bbl)
WTI			57.94				102.99
Encana realized liquids price1			43.78				69.53

¹ Realized prices include the impact of financial hedging.

 

		Encana Corporation

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Q2 Report  |  For the period ended June 30, 2015

 

 

Encana Corporation

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Q2 Report  |  For the period ended June 30, 2015

 

 

		Encana Corporation

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Q2 Report  |  For the period ended June 30, 2015

 

Management’s Discussion and Analysis

This Management’s Discussion and Analysis (“MD&A”) for Encana Corporation (“Encana” or the “Company”) should be read with the unaudited interim Condensed Consolidated Financial Statements for the period ended June 30, 2015 (“Interim Condensed Consolidated Financial Statements”), as well as the audited Consolidated Financial Statements and MD&A for the year ended December 31, 2014.

The Interim Condensed Consolidated Financial Statements and comparative information have been prepared in accordance with United States (“U.S.”) generally accepted accounting principles (“U.S. GAAP”) and in U.S. dollars, except where another currency has been indicated. References to C$ are to Canadian dollars. Encana’s financial results are consolidated in Canadian dollars; however, the Company has adopted the U.S. dollar as its reporting currency to facilitate a more direct comparison to other North American oil and gas companies. Production volumes are presented on an after royalties basis consistent with U.S. oil and gas reporting standards and the disclosure of U.S. oil and gas companies. The term “liquids” is used to represent oil, natural gas liquids (“NGLs” or “NGL”) and condensate. The term “liquids rich” is used to represent natural gas streams with associated liquids volumes. This document is dated July 23, 2015.

For convenience, references in this document to “Encana”, the “Company”, “we”, “us”, “our” and “its” may, where applicable, refer only to or include any relevant direct and indirect subsidiary corporations and partnerships (“Subsidiaries”) of Encana Corporation, and the assets, activities and initiatives of such Subsidiaries.

Certain measures in this document do not have any standardized meaning as prescribed by U.S. GAAP and, therefore, are considered non-GAAP measures. Non-GAAP measures are commonly used in the oil and gas industry and by Encana to provide shareholders and potential investors with additional information regarding the Company’s liquidity and its ability to generate funds to finance its operations. Non-GAAP measures include: Cash Flow; Free Cash Flow; Operating Earnings (Loss); Upstream Operating Cash Flow, excluding Hedging; Operating Netback; Debt to Debt Adjusted Cash Flow; and Debt to Adjusted Capitalization. Further information regarding these measures can be found in the Non-GAAP Measures section of this MD&A, including reconciliations of Cash from Operating Activities to Cash Flow and Free Cash Flow, and of Net Earnings (Loss) Attributable to Common Shareholders to Operating Earnings (Loss).

The following volumetric measures may be abbreviated throughout this MD&A: thousand cubic feet (“Mcf”); million cubic feet (“MMcf”) per day (“MMcf/d”); barrel (“bbl”); thousand barrels (“Mbbls”) per day (“Mbbls/d”); barrels of oil equivalent (“BOE”) per day (“BOE/d”); thousand barrels of oil equivalent (“MBOE”) per day (“MBOE/d”); million British thermal units (“MMBtu”).

Readers should also read the Advisory section located at the end of this document, which provides information on Forward-Looking Statements and Oil and Gas Information.

 

MD&A Prepared using U.S. GAAP in US$

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Q2 Report  |  For the period ended June 30, 2015

 

Encana’s Strategic Objectives

Encana is a leading North American energy producer that is focused on developing its strong portfolio of resource plays producing natural gas, oil and NGLs. Encana is committed to growing long-term shareholder value through a disciplined focus on generating profitable growth. The Company is pursuing the key business objectives of balancing its commodity portfolio, focusing capital investments in strategic high return scalable projects, maintaining portfolio flexibility to respond to changing market conditions, maximizing profitability through operating efficiencies, reducing costs and preserving balance sheet strength.

Encana continually strives to improve operating efficiencies, foster technological innovation and lower its cost structures, while reducing its environmental footprint through play optimization. The Company’s resource play hub model utilizes highly integrated production facilities to develop resources by drilling multiple wells from central pad sites. Capital and operating efficiencies are achieved through repeatable operations, optimizing equipment and processes and by applying continuous improvement techniques.

Encana hedges a portion of its expected natural gas and oil production volumes. The Company’s hedging program reduces volatility and helps sustain Cash Flow and operating netbacks during periods of lower prices. Further information on the Company’s commodity price positions as at June 30, 2015 can be found in the Results Overview section of this MD&A and in Note 21 to the Interim Condensed Consolidated Financial Statements.

Additional information on expected results can be found in Encana’s 2015 Corporate Guidance on the Company’s website www.encana.com.

 

Encana’s Business

Encana’s reportable segments are determined based on the Company’s operations and geographic locations as follows:

 

•

Canadian Operations includes the exploration for, development of, and production of natural gas, oil and NGLs and other related activities within Canada.

 

•

USA Operations includes the exploration for, development of, and production of natural gas, oil and NGLs and other related activities within the U.S.

 

•

Market Optimization is primarily responsible for the sale of the Company’s proprietary production. These results are reported in the Canadian and USA Operations. Market optimization activities include third party purchases and sales of product to provide operational flexibility for transportation commitments, product type, delivery points and customer diversification. These activities are reflected in the Market Optimization segment. Market Optimization sells substantially all of the Company’s upstream production to third party customers. Transactions between segments are based on market values and are eliminated on consolidation. Financial information is presented on an after eliminations basis within this MD&A.

Corporate and Other mainly includes unrealized gains or losses recorded on derivative financial instruments. Once the instruments are settled, the realized gains and losses are recorded in the reporting segment to which the derivative instruments relate.

 

		MD&A Prepared using U.S. GAAP in US$

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Q2 Report  |  For the period ended June 30, 2015

 

Results Overview

Highlights

 

In the three months ended June 30, 2015, Encana reported:

 

•

Cash Flow of $181 million and an Operating Loss of $167 million.

 

•

Net Loss of $1,610 million, including an after-tax non-cash ceiling test impairment of $1,328 million.

 

•

Average realized natural gas prices, including financial hedges, of $3.52 per Mcf. Average realized oil prices, including financial hedges, of $53.08 per bbl. Average realized NGL prices of $24.28 per bbl.

 

•

Average natural gas production volumes of 1,568 MMcf/d and average oil and NGL production volumes of 127.3 Mbbls/d.

 

•

Dividends paid of $0.07 per share.

In the six months ended June 30, 2015, Encana reported:

 

•

Cash Flow of $676 million and an Operating Loss of $148 million.

 

•

Net Loss of $3,317 million, including an after-tax non-cash ceiling test impairment of $2,550 million.

 

•

Average realized natural gas prices, including financial hedges, of $4.20 per Mcf. Average realized oil prices, including financial hedges, of $49.80 per bbl. Average realized NGL prices of $23.10 per bbl.

 

•

Average natural gas production volumes of 1,712 MMcf/d and average oil and NGL production volumes of 124.0 Mbbls/d.

 

•

Dividends paid of $0.14 per share.

 

•

Cash and cash equivalents of $496 million at period end.

Significant developments for the Company during the six months ended June 30, 2015 included the following:

 

•

Completed a bought deal offering of 85,616,500 common shares of Encana and the over-allotment option of an additional 12,842,475 common shares of Encana at a price of C$14.60 per common share (the “Share Offering”). The Share Offering was completed during March 2015 for aggregate gross proceeds of approximately C$1.44 billion.

 

•

Redeemed the Company’s $700 million 5.90 percent notes due December 1, 2017 and its C$750 million 5.80 percent medium-term notes due January 18, 2018, on April 6, 2015, using net proceeds from the Share Offering and cash on hand.

 

•

Closed the sale of the Company’s working interest in certain properties in central and southern Alberta to Ember Resources Inc. on January 15, 2015 for proceeds of approximately C$558 million, after closing adjustments.

 

•

Closed the sale of certain natural gas gathering and compression assets in northeastern British Columbia to Veresen Midstream Limited Partnership (“VMLP”) on March 31, 2015 for cash consideration net to Encana of approximately C$454 million, after closing adjustments.

 

MD&A Prepared using U.S. GAAP in US$

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Q2 Report  |  For the period ended June 30, 2015

 

Financial Results

 

 

		Six months ended June 30										2015										2014																		2013
($ millions, except as indicated)		2015				2014						Q2				Q1						Q4				Q3				Q2				Q1						Q4				Q3
Cash Flow (1)		$	676			$	1,750					$	181			$	495					$	377			$	807			$	656			$	1,094					$	677			$	660
$ per share - diluted			0.85				2.36						0.22				0.65						0.51				1.09				0.89				1.48						0.91				0.89
Operating Earnings (Loss) (1), (2)			(148	)			686						(167	)			19						35				281				171				515						226				150
$ per share - diluted			(0.19	)			0.93						(0.20	)			0.03						0.05				0.38				0.23				0.70						0.31				0.20
Net Earnings (Loss) Attributable to Common Shareholders			(3,317	)			387						(1,610	)			(1,707	)					198				2,807				271				116						(251	)			188
$ per share - basic & diluted			(4.15	)			0.52						(1.91	)			(2.25	)					0.27				3.79				0.37				0.16						(0.34	)			0.25
Revenues, Net of Royalties			2,079				3,480						830				1,249						2,254				2,285				1,588				1,892						1,423				1,392
Realized Hedging Gain (Loss), before tax			401				(243	)					161				240						124				28				(102	)			(141	)					174				175
Unrealized Hedging Gain (Loss), before tax			(414	)			(276	)					(278	)			(136	)					489				231				9				(285	)					(301	)			(128	)
Upstream Operating Cash Flow			1,181				2,115						479				702						821				982				800				1,315						901				794
Upstream Operating Cash Flow Excluding Realized Hedging (1)			769				2,353						315				454						694				952				898				1,455						728				622
Capital Investment			1,479				1,071						743				736						857				598				560				511						717				641
Net Acquisitions & (Divestitures) (3)			(978	)			628						(140	)			(838	)					50				(2,007	)			652				(24	)					(72	)			(51	)
Free Cash Flow (1)			(803	)			679						(562	)			(241	)					(480	)			209				96				583						(40	)			19
Ceiling Test Impairments, after tax			(2,550	)			-						(1,328	)			(1,222	)					-				-				-				-						-				-
Gain (Loss) on Divestitures, after tax			11				135						1				10						(11	)			2,399				135				-						-				-
Production Volumes
Natural Gas (MMcf/d)			1,712				2,675						1,568				1,857						1,861				2,199				2,541				2,809						2,744				2,723
Oil & NGLs (Mbbls/d)
Oil			82.7				33.1						86.2				79.2						68.8				62.1				34.2				32.1						33.0				27.2
NGLs			41.3				34.9						41.1				41.5						37.6				41.9				34.0				35.8						33.0				31.0
Total Oil & NGLs			124.0				68.0						127.3				120.7						106.4				104.0				68.2				67.9						66.0				58.2
Total Production (MBOE/d)			409.3				513.8						388.7				430.1						416.7				470.6				491.8				536.1						523.4				512.1
Production Mix (%)
Natural Gas			70				87						67				72						74				78				86				87						87				89
Oil & NGLs			30				13						33				28						26				22				14				13						13				11

 

(1)	A non-GAAP measure, which is defined in the Non-GAAP Measures section of this MD&A.

(2)	In continued support of Encana’s strategy, organizational structure changes were formalized in Q2 2015 and resulted in a revision to the Q1 2015 Operating Earnings to exclude restructuring charges incurred in the first quarter.

(3)	Excludes the impact of the PrairieSky Royalty Ltd. divestiture and the Athlon Energy Inc. acquisition during 2014, as summarized in the Net Capital Investment section of this MD&A.

Encana’s quarterly net earnings can be significantly impacted by fluctuations in commodity prices, realized and unrealized hedging gains and losses, production volumes, foreign exchange rates, ceiling test impairments and gains or losses on divestitures, which are provided in the Financial Results table and Prices and Foreign Exchange Rates table within this MD&A. Quarterly net earnings are also impacted by Encana’s interim income tax expense calculated using the estimated annual effective income tax rate as discussed in the Other Operating

 

		MD&A Prepared using U.S. GAAP in US$

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Q2 Report  |  For the period ended June 30, 2015

 

Results section of this MD&A. Quarterly net earnings are also impacted by acquisition and divestiture transactions, which are discussed in the Net Capital Investment section of this MD&A.

Under full cost accounting, the carrying amount of Encana’s natural gas and oil properties within each country cost centre is subject to a ceiling test performed quarterly. Ceiling test impairments are recognized when the capitalized costs, net of accumulated depletion and the related deferred income taxes, exceed the sum of the estimated after-tax future net cash flows from proved reserves as calculated under Securities and Exchange Commission (“SEC”) requirements using the 12-month average trailing prices and discounted at 10 percent.

In the second quarter and first six months of 2015, the Company recognized after-tax non-cash ceiling test impairments of $1,328 million and $2,550 million, respectively, in the U.S. cost centre. The non-cash ceiling test impairments primarily resulted from the decline in the 12-month average trailing commodity prices. Further declines in the 12-month average trailing commodity prices could reduce proved reserves values and result in the recognition of future ceiling test impairments. Future ceiling test impairments can also result from changes to reserves estimates, future development costs, capitalized costs and unproved property costs. Proceeds received from natural gas and oil divestitures are generally deducted from the Company’s capitalized costs and can reduce the likelihood of ceiling test impairments.

The Company believes that the discounted after-tax future net cash flows from proved reserves required to be used in the ceiling test calculation are not indicative of the fair market value of Encana’s natural gas and oil properties or the future net cash flows expected to be generated from such properties. The discounted after-tax future net cash flows do not consider the fair market value of unamortized unproved properties, or probable or possible natural gas and liquids reserves. In addition, there is no consideration given to the effect of future changes in commodity prices. Encana manages its business using estimates of reserves and resources based on forecast prices and costs.

Three months ended June 30, 2015 versus June 30, 2014

Cash Flow of $181 million decreased $475 million in the three months ended June 30, 2015 and was impacted by the following significant items:

 

•

Average realized natural gas prices, excluding financial hedges, were $2.37 per Mcf compared to $4.46 per Mcf in 2014 reflecting lower benchmark prices. Lower realized natural gas prices decreased revenues $285 million. Average realized liquids prices, excluding financial hedges, were $43.83 per bbl compared to $71.23 per bbl in 2014 reflecting lower benchmark prices. Lower realized liquids prices decreased revenues $208 million.

 

•

Average natural gas production volumes of 1,568 MMcf/d decreased 973 MMcf/d from 2,541 MMcf/d in 2014 primarily due to divestitures, natural declines in the USA Operations and lower production from Deep Panuke, partially offset by a successful drilling program in Montney. Lower natural gas volumes decreased revenues $408 million. Average oil and NGL production volumes of 127.3 Mbbls/d increased 59.1 Mbbls/d from 68.2 Mbbls/d in 2014 primarily due to acquisitions and successful drilling programs in oil and liquids rich natural gas plays, partially offset by divestitures. Higher oil and NGL volumes increased revenues $271 million.

 

•

Realized financial hedging gains before tax were $161 million compared to losses of $102 million in 2014.

 

•

Transportation and processing expense decreased $100 million primarily due to divestitures, the lower U.S./Canadian dollar exchange rate and lower production from Deep Panuke, partially offset by higher liquids volumes in Montney.

 

•

Operating expense increased $31 million primarily due to liquids-weighted acquisitions, partially offset by divestitures, lower non-cash long-term compensation costs resulting from the decrease in the Encana share price and the lower U.S./Canadian dollar exchange rate.

 

•

Interest expense increased $156 million primarily due to a one-time interest payment of approximately $165 million resulting from the early redemption of Encana’s $700 million 5.90 percent notes due December 1, 2017 and C$750 million 5.80 percent medium-term notes due January 18, 2018.

 

MD&A Prepared using U.S. GAAP in US$

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Q2 Report  |  For the period ended June 30, 2015

 

Operating Loss in the second quarter of 2015 was $167 million compared to Operating Earnings of $171 million in 2014 primarily due to the items discussed in the Cash Flow section. Operating Loss for the second quarter of 2015 was also impacted by a higher foreign exchange loss on settlements and the revaluation of other monetary assets and liabilities and deferred tax.

Net Loss Attributable to Common Shareholders in the second quarter of 2015 was $1,610 million compared to Net Earnings Attributable to Common Shareholders of $271 million in 2014 primarily due to an after-tax non-cash ceiling test impairment and the items discussed in the Cash Flow and Operating Earnings sections. Net Loss for the second quarter of 2015 was also impacted by after-tax unrealized hedging losses, a lower after-tax gain on divestitures, a lower after-tax non-operating foreign exchange gain and deferred tax.

Six months ended June 30, 2015 versus June 30, 2014

Cash Flow of $676 million decreased $1,074 million in the six months ended June 30, 2015 and was impacted by the following significant items:

 

•

Average realized natural gas prices, excluding financial hedges, were $3.00 per Mcf compared to $5.46 per Mcf in 2014 reflecting lower benchmark prices. Lower realized natural gas prices decreased revenues $735 million. Average realized liquids prices, excluding financial hedges, were $39.14 per bbl compared to $70.24 per bbl in 2014 reflecting lower benchmark prices. Lower realized liquids prices decreased revenues $416 million.

 

•

Average natural gas production volumes of 1,712 MMcf/d decreased 963 MMcf/d from 2,675 MMcf/d in 2014 primarily due to divestitures, natural declines in the USA Operations and lower production from Deep Panuke, partially offset by a successful drilling program in Montney. Lower natural gas volumes decreased revenues $980 million. Average oil and NGL production volumes of 124.0 Mbbls/d increased 56.0 Mbbls/d from 68.0 Mbbls/d in 2014 primarily due to acquisitions and successful drilling programs in oil and liquids rich natural gas plays, partially offset by divestitures. Higher oil and NGL volumes increased revenues $427 million.

 

•

Realized financial hedging gains before tax were $401 million compared to losses of $243 million in 2014.

 

•

Transportation and processing expense decreased $139 million primarily due to divestitures, the lower U.S./Canadian dollar exchange rate and lower production from Deep Panuke, partially offset by higher liquids volumes in Montney.

 

•

Interest expense increased $134 million primarily due to a one-time interest payment of approximately $165 million resulting from the early redemption of Encana’s $700 million 5.90 percent notes due December 1, 2017 and C$750 million 5.80 percent medium-term notes due January 18, 2018.

Operating Loss in the first six months of 2015 was $148 million compared to Operating Earnings of $686 million in 2014 primarily due to the items discussed in the Cash Flow section. Operating Loss for the first six months of 2015 was also impacted by a higher foreign exchange loss on settlements and the revaluation of other monetary assets and liabilities and deferred tax.

Net Loss Attributable to Common Shareholders in the first six months of 2015 was $3,317 million compared to Net Earnings Attributable to Common Shareholders of $387 million in 2014 primarily due to after-tax non-cash ceiling test impairments and the items discussed in the Cash Flow and Operating Earnings sections. Net Loss for the first six months of 2015 was also impacted by a higher after-tax non-operating foreign exchange loss, a lower after-tax gain on divestitures, higher after-tax unrealized hedging losses and deferred tax.

 

		MD&A Prepared using U.S. GAAP in US$

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Q2 Report  |  For the period ended June 30, 2015

 

Prices and Foreign Exchange Rates

 

 

		Six months ended June 30										2015										2014																		2013
(average for the period)		2015				2014						Q2				Q1						Q4				Q3				Q2				Q1						Q4				Q3
Encana Realized Pricing
Including Hedging
Natural Gas ($/Mcf)		$	4.20			$	4.99					$	3.52			$	4.78					$	4.16			$	4.03			$	4.08			$	5.82					$	4.34			$	4.00
Oil & NGLs ($/bbl)
Oil			49.80				88.00						53.08				46.17						80.38				90.22				89.55				86.34						85.39				90.42
NGLs			23.10				51.64						24.28				21.92						40.87				48.76				49.39				53.79						48.59				46.35
Total Oil & NGLs			40.91				69.36						43.78				37.83						66.40				73.50				69.53				69.19						67.01				66.95
Total ($/BOE)			29.94				35.14						28.53				31.24						35.55				35.06				30.75				39.22						31.23				28.85
Excluding Hedging
Natural Gas ($/Mcf)			3.00				5.46						2.37				3.53						3.94				3.88				4.46				6.37						3.69				3.26
Oil & NGLs ($/bbl)
Oil			47.15				89.80						53.15				40.53						66.38				90.18				92.93				86.43						82.54				96.09
NGLs			23.10				51.64						24.28				21.92						40.87				48.76				49.39				53.79						48.59				46.35
Total Oil & NGLs			39.14				70.24						43.83				34.13						57.35				73.48				71.23				69.23						65.58				69.60
Total ($/BOE)			24.38				37.70						23.90				24.82						32.25				34.36				32.93				42.12						27.63				25.23
Natural Gas Price Benchmarks
NYMEX ($/MMBtu)			2.81				4.80						2.64				2.98						4.00				4.06				4.67				4.94						3.60				3.58
AECO (C$/Mcf)			2.81				4.72						2.67				2.95						4.01				4.22				4.68				4.76						3.15				2.82
Algonquin City Gate ($/MMBtu)			6.80				12.21						2.24				11.41						4.99				2.97				4.23				20.28						7.80				3.98
Basis Differential ($/MMBtu) AECO/NYMEX			0.53				0.50						0.50				0.57						0.44				0.16				0.40				0.60						0.59				0.89
Oil Price Benchmarks
West Texas Intermediate (WTI) ($/bbl)			53.29				100.84						57.94				48.64						73.15				97.17				102.99				98.68						97.46				105.81
Edmonton Light Sweet (C$/bbl)			59.82				102.72						67.71				51.94						75.69				97.16				105.61				99.83						86.58				103.65
Foreign Exchange
Average U.S./Canadian Dollar Exchange Rate			0.810				0.912						0.813				0.806						0.881				0.918				0.917				0.906						0.953				0.963

Encana’s financial results are influenced by fluctuations in commodity prices, price differentials and the U.S./Canadian dollar exchange rate. In the second quarter and first six months of 2015, Encana’s average realized natural gas price, excluding hedging, reflected lower benchmark prices compared to 2014. Hedging activities contributed $1.15 per Mcf to Encana’s average realized natural gas price in the second quarter of 2015 and $1.20 per Mcf in the first six months of 2015. The average realized natural gas price for production from Deep Panuke was $9.40 per Mcf in the first six months of 2015 compared to $11.31 per Mcf in 2014 and increased Encana’s average realized natural gas price $0.43 per Mcf in the first six months of 2015 compared to $0.60 per Mcf in 2014.

In the second quarter and first six months of 2015, Encana’s average realized oil and NGL prices, excluding hedging, reflected lower benchmark prices compared to 2014. Hedging activities reduced Encana’s average realized oil price $0.07 per bbl in the second quarter of 2015 and contributed $2.65 per bbl in the first six months of 2015.

As a means of managing commodity price volatility and its impact on cash flows, Encana enters into various financial hedge agreements. Unsettled derivative financial contracts are recorded at the date of the financial statements based on the fair value of the contracts. Changes in fair value result from volatility in forward curves of

 

MD&A Prepared using U.S. GAAP in US$

---

Q2 Report  |  For the period ended June 30, 2015

 

commodity prices and changes in the balance of unsettled contracts between periods. The changes in fair value are recognized in revenue as unrealized hedging gains and losses. Realized hedging gains and losses are recognized in revenue when derivative financial contracts are settled.

At June 30, 2015, Encana has hedged approximately 1,000 MMcf/d of expected July to December 2015 natural gas production using NYMEX fixed price contracts at an average price of $4.29 per Mcf. In addition, Encana has hedged approximately 59.4 Mbbls/d of expected July to December 2015 oil production using WTI fixed price contracts at an average price of $61.96 per bbl and approximately 38.0 Mbbls/d of expected 2016 oil production at an average price of $62.83 per bbl.

The Company’s hedging program helps sustain Cash Flow and operating netbacks during periods of lower prices. For additional information, see the Risk Management – Financial Risks section of this MD&A.

Foreign Exchange

As disclosed in the Prices and Foreign Exchange Rates table, the average U.S./Canadian dollar exchange rate decreased 0.104 in the second quarter of 2015 compared to the second quarter of 2014 and 0.102 in the first six months of 2015 compared to the first six months of 2014. The table below summarizes selected foreign exchange impacts on Encana’s financial results when compared to the same periods in 2014.

 

		Three months ended June 30										Six months ended June 30
		$ millions				$/BOE						$ millions				$/BOE
Increase (Decrease) in:
Capital Investment			$        (40)										$        (72)
Transportation and Processing Expense			(25)				$  (0.72)						(49)				$  (0.66)
Operating Expense			(9)				(0.25)						(19)				(0.25)
Administrative Expense			(8)				(0.23)						(16)				(0.21)
Depreciation, Depletion and Amortization			(19)				(0.53)						(38)				(0.51)

Price Sensitivities

Natural gas and liquids prices fluctuate in response to changing market forces, creating varying impacts on Encana’s financial results. The Company’s potential exposure to commodity price fluctuations is summarized in the table below, which shows the estimated effects that certain price changes would have had on the Company’s Cash Flow and Operating Earnings (Loss) for the second quarter of 2015. The price sensitivities below are based on business conditions, transactions and production volumes during the second quarter of 2015. Accordingly, these sensitivities may not be indicative of financial results for other periods, under other economic circumstances or with additional fluctuations in commodity prices.

 

Impact On

($ millions, except as indicated)

Price Change (1)

Cash Flow

Operating Earnings (Loss)

Increase or Decrease in:

NYMEX Natural Gas Price

+/-$

0.50/MMBtu

$        25

$        17

WTI Oil Price

+/- $

10.00/bbl

45

30

(1)	Assumes only one variable changes while all other variables are held constant.

 

		MD&A Prepared using U.S. GAAP in US$

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Q2 Report  |  For the period ended June 30, 2015

 

Net Capital Investment

 

		Three months ended June 30										Six months ended June 30
($ millions)		2015				2014						2015				2014
Canadian Operations		$	114			$	350					$	265			$	631
USA Operations			628				206						1,211				432
Market Optimization			-				1						-				2
Corporate & Other			1				3						3				6
Capital Investment			743				560						1,479				1,071
Acquisitions			3				2,923						38				2,946
Divestitures			(143	)			(2,271	)					(1,016	)			(2,318	)
Net Acquisitions & (Divestitures)			(140	)			652						(978	)			628
Net Capital Investment		$	603			$	1,212					$	501			$	1,699
Capital Investment by Play
		Three months ended June 30										Six months ended June 30
($ millions)		2015				2014						2015				2014
Canadian Operations
Montney (1)		$	48			$	210					$	127			$	418
Duvernay			57				81						127				152
Other Upstream Operations
Wheatland (2)			4				12						4				30
Bighorn			-				10						-				19
Deep Panuke			1				2						3				(1	)
Other and emerging (1)			4				35						4				13
Total Canadian Operations		$	114			$	350					$	265			$	631
USA Operations
Eagle Ford		$	175			$	12					$	372			$	12
Permian			325				-						542				-
DJ Basin			56				69						144				128
San Juan			23				50						59				102
Other Upstream Operations
Piceance			3				5						6				26
Haynesville			10				(5	)					12				33
Jonah			-				16						-				27
East Texas			-				-						-				10
Other and emerging			36				59						76				94
Total USA Operations		$	628			$	206					$	1,211			$	432
Capital Investment – Growth Assets (1)		$	700			$	449					$	1,413			$	859

 

(1)	Montney has been realigned to include certain capital investments which were previously reported in Other and emerging.

(2)	Wheatland was previously presented as Clearwater.

Growth assets includes Encana’s top four strategic assets – Montney, Duvernay, Eagle Ford and Permian – as well as the DJ Basin, San Juan and the Tuscaloosa Marine Shale (“TMS”), which represent additional high-quality investment opportunities. Other Upstream Operations includes capital investment from plays that are not part of the Company’s current strategic focus as well as prospective plays that are under appraisal, including the TMS, which is reported within Other and emerging in the USA Operations. For the second quarter and first six months of 2015, capital investment in the TMS was $16 million and $42 million, respectively (2014 – $27 million and $47 million, respectively).

Capital investment associated with the Clearwater lands transferred to PrairieSky Royalty Ltd. (“PrairieSky”) was included in Encana’s Wheatland play until September 25, 2014, after which Encana no longer held an interest in PrairieSky.

 

MD&A Prepared using U.S. GAAP in US$

---

Q2 Report  |  For the period ended June 30, 2015

 

Capital Investment

Capital investment during the first six months of 2015 was $1,479 million compared to $1,071 million in 2014. The Company’s disciplined capital spending focused on investment in its growth assets, as well as executing drilling programs with joint venture partners. During the first six months of 2015, capital spending in the Company’s growth assets totaled $1,413 million (2014 – $859 million), representing approximately 96 percent (2014 – 80 percent) of the Company’s capital investment, with $1,168 million (2014 – $582 million) spent on Encana’s top four strategic assets.

Divestitures

Divestitures in the first six months of 2015 were $879 million in the Canadian Operations and $84 million in the USA Operations, which primarily included the transactions discussed below, as well as the sale of land and properties that do not complement Encana’s existing portfolio of assets.

The Canadian Operations included approximately C$558 million ($468 million), after closing adjustments, for the sale of the Company’s working interest in certain assets included in Wheatland located in central and southern Alberta which comprised approximately 1.2 million net acres of land that contained over 6,800 producing wells. Immediately following the sale, Encana retained a working interest in approximately 1.1 million net acres in the area. The Canadian Operations also included approximately C$454 million ($358 million), after closing adjustments, in cash consideration net to Encana for the sale of certain natural gas gathering and compression assets in northeastern British Columbia to VMLP. In conjunction with the sale, VMLP will undertake the expansion of future midstream services and will also provide natural gas gathering and processing in Montney to Encana and the Cutbank Ridge Partnership. Further information can be found in Note 16 to the Interim Condensed Consolidated Financial Statements.

Divestitures in the first six months of 2014 were $121 million in the Canadian Operations and $2,170 million in the USA Operations. The USA Operations primarily included approximately $1.6 billion, after closing adjustments, for the sale of the Jonah properties and approximately $427 million for the sale of certain properties in East Texas.

Amounts received from the divestiture transactions above have been deducted from the respective Canadian and U.S. full cost pools, except for the sale of the Jonah properties. The proved reserves associated with the Jonah divestiture exceeded 25 percent of Encana’s proved reserves in the U.S. cost centre. The carrying amount of the assets was deducted from the full cost pool and the remainder of the proceeds was recognized as a gain on sale of approximately $212 million, before tax. Goodwill of $68 million was allocated to the divestiture.

Acquisitions

Acquisitions in the first six months of 2014 were $2,944 million in the USA Operations which primarily related to the acquisition of Eagle Ford.

2014 Capital Transactions

The significant acquisition and divestiture transactions below, which occurred during 2014, have impacted the Company’s production volume and operating cash flow variances for the second quarter and first six months of 2015. A comprehensive discussion of these transactions is included in the annual MD&A for the year ended December 31, 2014.

 

Transaction		Location		Closing Date
Canadian Operations
Divestiture of Encana’s remaining investment in PrairieSky (1),  (2)		Alberta			September 26, 2014
Sale of Bighorn assets		Alberta			September 30, 2014
USA Operations
Sale of Jonah properties		Wyoming			May 12, 2014
Sale of East Texas properties		Texas			June 19, 2014
Acquisition of properties in the Eagle Ford shale formation		Texas			June 20, 2014
Acquisition of Athlon Energy Inc. with assets in the Permian Basin (1)		Texas			November 13, 2014

 

(1)	Transactions involved the disposition or acquisition of common shares and, therefore, were not part of the Company’s net acquisition and divestiture activity for 2014.

(2)	Encana completed the initial public offering of PrairieSky on May 29, 2014.

 

		MD&A Prepared using U.S. GAAP in US$

---

Q2 Report  |  For the period ended June 30, 2015

 

Production Volumes

 

  

		Three months ended June 30															Six months ended June 30
(average daily, after royalties)		2015					2014										2015					2014
Natural Gas (MMcf/d)				1,568					2,541										1,712					2,675
Oil (Mbbls/d)				86.2					34.2										82.7					33.1
NGLs (Mbbls/d)				41.1					34.0										41.3					34.9
Total Oil & NGLs (Mbbls/d)				127.3					68.2										124.0					68.0
Total Production (MBOE/d)				388.7					491.8										409.3					513.8
Production Mix (%)
Natural Gas				67					86										70					87
Oil & NGLs				33					14										30					13

Production Volumes by Play

 

		Three months ended June 30																				Six months ended June 30
(average daily, after royalties)		Natural Gas (MMcf/d)										Oil & NGLs (Mbbls/d)										Natural Gas (MMcf/d)										Oil & NGLs (Mbbls/d)
		2015				2014						2015				2014						2015				2014						2015				2014
Canadian Operations
Montney (1)			685				604						21.6				13.3						701				612						22.5				14.8
Duvernay			17				9						3.0				1.8						17				9						2.9				1.6
Other Upstream Operations
Wheatland (2)			76				305						1.2				11.3						94				314						1.5				11.3
Bighorn			-				230						-				11.0						2				238						-				11.5
Deep Panuke			32				243						-				-						107				248						-				-
Other and emerging (1)			71				72						0.5				-						83				95						0.1				-
Total Canadian Operations			881				1,463						26.3				37.4						1,004				1,516						27.0				39.2
USA Operations
Eagle Ford			36				5						39.8				5.0						36				2						37.9				2.5
Permian			38				-						29.5				-						36				-						28.1				-
DJ Basin			55				43						15.3				10.1						52				42						14.8				10.3
San Juan			15				7						6.4				3.9						14				7						6.6				3.3
Other Upstream Operations
Piceance			324				407						3.7				5.3						333				421						3.7				5.4
Haynesville			204				365						-				-						217				348						-				-
Jonah			-				124						-				2.5						-				203						-				3.6
East Texas			-				97						-				1.0						-				105						-				1.1
Other and emerging			15				30						6.3				3.0						20				31						5.9				2.6
Total USA Operations			687				1,078						101.0				30.8						708				1,159						97.0				28.8
Total Production Volumes			1,568				2,541						127.3				68.2						1,712				2,675						124.0				68.0
Total Production Volumes – Growth Assets (1)			846				668						121.3				35.3						856				672						117.8				33.4

 

(1)

Montney has been realigned to include certain production volumes which were previously reported in Other and emerging.

(2)

Wheatland was previously presented as Clearwater.

 

MD&A Prepared using U.S. GAAP in US$

---

Q2 Report  |  For the period ended June 30, 2015

 

Growth assets includes Encana’s top four strategic assets – Montney, Duvernay, Eagle Ford and Permian – as well as the DJ Basin, San Juan and the TMS, which represent additional high-quality investment opportunities. Other Upstream Operations includes production volumes from plays that are not part of the Company’s current strategic focus as well as prospective plays that are under appraisal, including the TMS, which is reported within Other and emerging in the USA Operations.

The production volumes associated with the Clearwater lands transferred to PrairieSky were included in Encana’s Wheatland play until September 25, 2014, after which Encana no longer held an interest in PrairieSky.

Natural Gas Production Volumes

In the second quarter of 2015, average natural gas production volumes of 1,568 MMcf/d decreased 973 MMcf/d from 2014. In the first six months of 2015, average natural gas production volumes of 1,712 MMcf/d decreased 963 MMcf/d from 2014.

The USA Operations volumes were lower in the second quarter and first six months of 2015 primarily due to the sales of the Jonah and East Texas properties in the second quarter of 2014 and natural declines in Haynesville and Piceance. The Canadian Operations volumes were lower in the second quarter and first six months of 2015 primarily due to the sale of the Bighorn assets in the third quarter of 2014, the sale of certain assets included in Wheatland in January 2015 and production declines at Deep Panuke due to the implementation of a seasonal operating strategy and a higher water production rate, partially offset by a successful drilling program in Montney.

Oil and NGL Production Volumes

In the second quarter of 2015, average oil and NGL production volumes of 127.3 Mbbls/d increased 59.1 Mbbls/d from 2014. In the first six months of 2015, average oil and NGL production volumes of 124.0 Mbbls/d increased 56.0 Mbbls/d from 2014.

The USA Operations volumes were higher in the second quarter and first six months of 2015 primarily due to the acquisitions of Eagle Ford and the Permian assets in the second and fourth quarters of 2014, respectively, and successful drilling programs in Eagle Ford, Permian, the DJ Basin, the TMS and San Juan, partially offset by the sales of the Jonah and East Texas properties in the second quarter of 2014. The Canadian Operations volumes were lower in the second quarter and first six months of 2015 primarily due to the sales of the Bighorn assets and the Company’s investment in PrairieSky in the third quarter of 2014, partially offset by successful drilling programs in Montney and Duvernay.

 

		MD&A Prepared using U.S. GAAP in US$

---

Q2 Report  |  For the period ended June 30, 2015

 

Results of Operations

Canadian Operations

 

Operating Cash Flow

 

		Three months ended June 30
		Natural Gas										Oil & NGLs										Total (1)
($ millions)		2015				2014						2015				2014						2015				2014
Revenues, Net of Royalties, excluding Hedging		$	193			$	569					$	91			$	227					$	286			$	803
Realized Financial Hedging Gain (Loss)			106				(44	)					(5	)			(5	)					101				(49	)
Revenues, Net of Royalties			299				525						86				222						387				754
Expenses
Production and mineral taxes			-				-						-				4						-				4
Transportation and processing			158				209						13				16						171				225
Operating			40				72						5				4						45				78
Operating Cash Flow		$	101			$	244					$	68			$	198					$	171			$	447
Production Volumes
		Three months ended June 30
		Natural Gas   (MMcf/d)										Oil & NGLs   (Mbbls/d)										Total (MBOE/d)
		2015				2014						2015				2014						2015				2014
Production Volumes – After Royalties			881				1,463						26.3				37.4						173.2				281.4
Operating Netback (2)
		Three months ended June 30
		Natural Gas ($/Mcf)										Oil & NGLs ($/bbl)										Total ($/BOE)
		2015				2014						2015				2014						2015				2014
Revenues, Net of Royalties, excluding Hedging		$	2.39			$	4.27					$	38.57			$	66.13					$	18.05			$	31.02
Realized Financial Hedging Gain (Loss)			1.32				(0.33	)					(2.21	)			(1.22	)					6.39				(1.89	)
Revenues, Net of Royalties			3.71				3.94						36.36				64.91						24.44				29.13
Expenses
Production and mineral taxes			-				-						-				1.12						-				0.16
Transportation and processing			1.97				1.57						5.46				4.60						10.85				8.76
Operating			0.49				0.55						1.91				1.06						2.80				2.98
Operating Netback		$	1.25			$	1.82					$	28.99			$	58.13					$	10.79			$	17.23

 

(1)

Also includes other revenues and expenses, such as third party processing, with no associated volumes.

(2)

A Non-GAAP measure as defined in the Non-GAAP Measures section of this MD&A.

 

MD&A Prepared using U.S. GAAP in US$

---

Q2 Report  |  For the period ended June 30, 2015

 

Three months ended June 30, 2015 versus June 30, 2014

Operating Cash Flow of $171 million decreased $276 million and was impacted by the following significant items:

 

•

Lower natural gas prices reflected lower benchmark prices, which decreased revenues $148 million. Lower liquids prices reflected lower benchmark prices, which decreased revenues $68 million.

 

•

Average natural gas production volumes of 881 MMcf/d were lower by 582 MMcf/d, which decreased revenues $228 million. Average oil and NGL production volumes of 26.3 Mbbls/d were lower by 11.1 Mbbls/d, which decreased revenues $68 million. Changes in production volumes are discussed in the Production Volumes section of this MD&A.

 

•

Realized financial hedging gains were $101 million compared to losses of $49 million in 2014.

 

•

Transportation and processing expense decreased $54 million primarily due to the sale of the Bighorn assets in the third quarter of 2014, the lower U.S./Canadian dollar exchange rate and production declines at Deep Panuke, partially offset by higher liquids volumes in Montney.

 

•

Operating expense decreased $33 million primarily due to the sale of certain assets included in Wheatland in January 2015, the sale of the Bighorn assets in the third quarter of 2014, the lower U.S./Canadian dollar exchange rate and lower long-term compensation costs due to the decrease in the Encana share price.

 

		MD&A Prepared using U.S. GAAP in US$

---

Q2 Report  |  For the period ended June 30, 2015

 

Operating Cash Flow

 

		Six months ended June 30
		Natural Gas										Oil & NGLs										Total (1)
($ millions)		2015				2014						2015				2014						2015				2014
Revenues, Net of Royalties, excluding Hedging		$	589			$	1,586					$	168			$	472					$	762			$	2,071
Realized Financial Hedging Gain (Loss)			260				(119	)					(3	)			(5	)					257				(124	)
Revenues, Net of Royalties			849				1,467						165				467						1,019				1,947
Expenses
Production and mineral taxes			-				2						-				7						-				9
Transportation and processing			321				410						27				30						348				440
Operating			76				156						11				10						87				170
Operating Cash Flow		$	452			$	899					$	127			$	420					$	584			$	1,328
Production Volumes
		Six months ended June 30
		Natural Gas (MMcf/d)										Oil & NGLs (Mbbls/d)										Total (MBOE/d)
		2015				2014						2015				2014						2015				2014
Production Volumes – After Royalties			1,004				1,516						27.0				39.2						194.4				291.8
Operating Netback (2)
		Six months ended June 30
		Natural Gas ($/Mcf)										Oil & NGLs ($/bbl)										Total ($/BOE)
		2015				2014						2015				2014						2015				2014
Revenues, Net of Royalties, excluding Hedging		$	3.23			$	5.77					$	34.53			$	66.25					$	21.50			$	38.85
Realized Financial Hedging Gain (Loss)			1.43				(0.43	)					(0.68	)			(0.63	)					7.30				(2.35	)
Revenues, Net of Royalties			4.66				5.34						33.85				65.62						28.80				36.50
Expenses
Production and mineral taxes			-				0.01						0.02				0.95						0.01				0.17
Transportation and processing			1.76				1.49						5.64				4.18						9.90				8.30
Operating			0.42				0.57						2.12				1.42						2.44				3.14
Operating Netback		$	2.48			$	3.27					$	26.07			$	59.07					$	16.45			$	24.89

 

(1)

Also includes other revenues and expenses, such as third party processing, with no associated volumes.

(2)

A Non-GAAP measure as defined in the Non-GAAP Measures section of this MD&A.

 

MD&A Prepared using U.S. GAAP in US$

---

Q2 Report  |  For the period ended June 30, 2015

 

Six months ended June 30, 2015 versus June 30, 2014

Operating Cash Flow of $584 million decreased $744 million and was impacted by the following significant items:

 

•

Lower natural gas prices reflected lower benchmark prices, which decreased revenues $458 million. The average realized natural gas price for production from Deep Panuke was $9.40 per Mcf compared to $11.31 per Mcf in 2014 and increased the average realized natural gas price $0.73 per Mcf compared to $1.09 per Mcf in 2014.

 

•

Lower liquids prices reflected lower benchmark prices, which decreased revenues $157 million.

 

•

Average natural gas production volumes of 1,004 MMcf/d were lower by 512 MMcf/d, which decreased revenues $539 million. Average oil and NGL production volumes of 27.0 Mbbls/d were lower by 12.2 Mbbls/d, which decreased revenues $147 million. Changes in production volumes are discussed in the Production Volumes section of this MD&A.

 

•

Realized financial hedging gains were $257 million compared to losses of $124 million in 2014.

 

•

Transportation and processing expense decreased $92 million primarily due to the sale of the Bighorn assets in the third quarter of 2014, the lower U.S./Canadian dollar exchange rate, the sale of certain assets included in Wheatland in January 2015, and production declines at Deep Panuke, partially offset by higher liquids volumes in Montney.

 

•

Operating expense decreased $83 million primarily due to the sale of certain assets included in Wheatland in January 2015, the lower U.S./Canadian dollar exchange rate, the sale of the Bighorn assets in the third quarter of 2014 and lower long-term compensation costs due to the decrease in the Encana share price.

Other Expenses

 

		Three months ended June 30										Six months ended June 30
($ millions, except as indicated)		2015				2014						2015				2014
Depreciation, depletion & amortization		$	68			$	165					$	173			$	337
Depletion rate ($/BOE)			4.31				6.45						4.91				6.36

Depreciation, depletion & amortization (“DD&A”) decreased in the second quarter and first six months of 2015 compared to 2014, primarily due to lower production volumes, the lower U.S./Canadian dollar exchange rate and a lower depletion rate. The depletion rate was impacted by the lower U.S./Canadian dollar exchange rate, and the sales of the Bighorn assets and the Company’s investment in PrairieSky in the third quarter of 2014.

 

		MD&A Prepared using U.S. GAAP in US$

---

Q2 Report  |  For the period ended June 30, 2015

 

USA Operations

 

Operating Cash Flow

 

		Three months ended June 30
		Natural Gas										Oil & NGLs										Total (1)
($ millions)		2015				2014						2015				2014						2015				2014
Revenues, Net of Royalties, excluding Hedging		$	146			$	463					$	414			$	215					$	566			$	687
Realized Financial Hedging Gain (Loss)			58				(43	)					5				(6	)					63				(49	)
Revenues, Net of Royalties			204				420						419				209						629				638
Expenses
Production and mineral taxes			5				14						21				15						26				29
Transportation and processing			142				177						2				-						144				177
Operating			46				65						104				12						151				79
Operating Cash Flow		$	11			$	164					$	292			$	182					$	308			$	353
Production Volumes
		Three months ended June 30
		Natural Gas (MMcf/d)										Oil & NGLs (Mbbls/d)										Total (MBOE/d)
		2015				2014						2015				2014						2015				2014
Production Volumes – After Royalties			687				1,078						101.0				30.8						215.5				210.4
Operating Netback (2)
		Three months ended June 30
		Natural Gas         ($/Mcf)										Oil & NGLs         ($/bbl)										Total         ($/BOE)
		2015				2014						2015				2014						2015				2014
Revenues, Net of Royalties, excluding Hedging		$	2.33			$	4.72					$	45.21			$	77.46					$	28.61			$	35.48
Realized Financial Hedging Gain (Loss)			0.93				(0.44	)					0.52				(2.28	)					3.22				(2.57	)
Revenues, Net of Royalties			3.26				4.28						45.73				75.18						31.83				32.91
Expenses
Production and mineral taxes			0.08				0.15						2.26				5.19						1.33				1.51
Transportation and processing			2.27				1.80						0.24				-						7.34				9.23
Operating			0.74				0.67						11.28				4.29						7.66				4.05
Operating Netback		$	0.17			$	1.66					$	31.95			$	65.70					$	15.50			$	18.12

 

(1)

Also includes other revenues and expenses, such as third party processing, with no associated volumes.

(2)

A Non-GAAP measure as defined in the Non-GAAP Measures section of this MD&A.

 

MD&A Prepared using U.S. GAAP in US$

---

Q2 Report  |  For the period ended June 30, 2015

 

Three months ended June 30, 2015 versus June 30, 2014

Operating Cash Flow of $308 million decreased $45 million and was impacted by the following significant items:

 

•

Lower natural gas prices reflected lower benchmark prices, which decreased revenues $137 million. Lower liquids prices reflected lower benchmark prices, which decreased revenues $140 million.

 

•

Average natural gas production volumes of 687 MMcf/d were lower by 391 MMcf/d, which decreased revenues $180 million. Average oil and NGL production volumes of 101.0 Mbbls/d were higher by 70.2 Mbbls/d, which increased revenues $339 million. Changes in production volumes are discussed in the Production Volumes section of this MD&A.

 

•

Realized financial hedging gains were $63 million compared to losses of $49 million in 2014.

 

•

Transportation and processing expense decreased $33 million primarily due to the sales of the Jonah and East Texas properties in the second quarter of 2014 and lower volumes processed mainly in Piceance.

 

•

Operating expense increased $72 million primarily due to the acquisitions of Eagle Ford and the Permian assets in the second and fourth quarters of 2014, respectively, partially offset by the sales of the Jonah and East Texas properties in the second quarter of 2014 and lower long-term compensation costs due to the decrease in the Encana share price.

 

		MD&A Prepared using U.S. GAAP in US$

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Q2 Report  |  For the period ended June 30, 2015

 

Operating Cash Flow

 

		Six months ended June 30
		Natural Gas										Oil & NGLs										Total(1)
($ millions)		2015				2014						2015				2014						2015				2014
Revenues, Net of Royalties, excluding Hedging		$	341			$	1,059					$	709			$	394					$	1,062			$	1,465
Realized Financial Hedging Gain (Loss)			112				(108	)					43				(6	)					155				(114	)
Revenues, Net of Royalties			453				951						752				388						1,217				1,351
Expenses
Production and mineral taxes			9				43						36				28						45				71
Transportation and processing			293				340						6				-						299				340
Operating			95				133						179				20						276				153
Operating Cash Flow		$	56			$	435					$	531			$	340					$	597			$	787
Production Volumes
		Six months ended June 30
		Natural Gas (MMcf/d)										Oil & NGLs (Mbbls/d)										Total (MBOE/d)
		2015				2014						2015				2014						2015				2014
Production Volumes – After Royalties			708				1,159						97.0				28.8						214.9				222.0
Operating Netback (2)
		Six months ended June 30
		Natural Gas ($/Mcf)										Oil & NGLs ($/bbl)										Total ($/BOE)
		2015				2014						2015				2014						2015				2014
Revenues, Net of Royalties, excluding Hedging		$	2.66			$	5.05					$	40.43			$	75.67					$	26.99			$	36.18
Realized Financial Hedging Gain (Loss)			0.88				(0.51	)					2.45				(1.21	)					3.99				(2.83	)
Revenues, Net of Royalties			3.54				4.54						42.88				74.46						30.98				33.35
Expenses
Production and mineral taxes			0.07				0.21						2.04				5.32						1.15				1.76
Transportation and processing			2.29				1.62						0.33				-						7.68				8.45
Operating			0.75				0.64						10.18				3.77						7.05				3.81
Operating Netback		$	0.43			$	2.07					$	30.33			$	65.37					$	15.10			$	19.33

 

(1)

Also includes other revenues and expenses, such as third party processing, with no associated volumes.

(2)

A Non-GAAP measure as defined in the Non-GAAP Measures section of this MD&A.

 

MD&A Prepared using U.S. GAAP in US$

---

Q2 Report  |  For the period ended June 30, 2015

 

Six months ended June 30, 2015 versus June 30, 2014

Operating Cash Flow of $597 million decreased $190 million and was impacted by the following significant items:

 

•

Lower natural gas prices reflected lower benchmark prices, which decreased revenues $277 million. Lower liquids prices reflected lower benchmark prices, which decreased revenues $259 million.

 

•

Average natural gas production volumes of 708 MMcf/d were lower by 451 MMcf/d, which decreased revenues $441 million. Average oil and NGL production volumes of 97.0 Mbbls/d were higher by 68.2 Mbbls/d, which increased revenues $574 million. Changes in production volumes are discussed in the Production Volumes section of this MD&A.

 

•

Realized financial hedging gains were $155 million compared to losses of $114 million in 2014.

 

•

Production and mineral taxes decreased $26 million primarily due to the sale of the Jonah properties in the second quarter of 2014 and lower commodity prices, partially offset by the acquisitions of Eagle Ford and the Permian assets in the second and fourth quarters of 2014, respectively.

 

•

Transportation and processing expense decreased $41 million primarily due to divestitures, which includes the sales of the Jonah and East Texas properties in the second quarter of 2014, partially offset by the acquisitions of Eagle Ford and the Permian assets in the second and fourth quarters of 2014, respectively.

 

•

Operating expense increased $123 million primarily due to the acquisitions of Eagle Ford and the Permian assets in the second and fourth quarters of 2014, respectively, partially offset by the sales of the Jonah and East Texas properties in the second quarter of 2014 and lower long-term compensation costs due to the decrease in the Encana share price.

 

Other Expenses

 

		Three months ended June 30										Six months ended June 30
($ millions, except as indicated)		2015				2014						2015				2014
Depreciation, depletion & amortization		$	301			$	203					$	637			$	415
Depletion rate ($/BOE)			15.18				10.60						16.07				10.33
Impairments			2,081				-						3,997				-

DD&A increased in the second quarter and first six months of 2015 compared to 2014, primarily due to a higher depletion rate. The depletion rate was higher primarily due to the acquisitions of Eagle Ford and the Permian assets in the second and fourth quarters of 2014, respectively, partially offset by the ceiling test impairment recognized in the first quarter of 2015 and a decrease in proved reserves as a result of the sale of the Jonah properties in the second quarter of 2014.

In the second quarter and first six months of 2015, the USA Operations recognized before-tax non-cash ceiling test impairments of $2,081 million and $3,997 million, respectively. The impairments primarily resulted from the decline in the 12-month average trailing commodity prices, which reduced the USA Operations proved reserves volumes and values as calculated under SEC requirements.

The 12-month average trailing prices used in the ceiling test calculations were based on the benchmark prices below. The benchmark prices were adjusted for basis differentials to determine local reference prices, transportation costs and tariffs, heat content and quality.

 

		Natural Gas				Oil & NGLs
		Henry Hub ($/MMBtu)				WTI ($/bbl)
12-Month Average Trailing Reserves Pricing (1)
June 30, 2015			3.38				71.68
December 31, 2014			4.34				94.99
June 30, 2014			4.10				100.27

 

(1)

All prices were held constant in all future years when estimating reserves.

 

		MD&A Prepared using U.S. GAAP in US$

---

Q2 Report  |  For the period ended June 30, 2015

 

Market Optimization

 

 

 

		Three months ended June 30										Six months ended June 30
($ millions)		2015				2014						2015				2014
Revenues		$	88			$	160					$	227			$	404
Expenses
Operating			8				13						24				26
Purchased product			79				142						200				370
Depreciation, depletion and amortization			-				1						-				4
		$	1			$	4					$	3			$	4

Market Optimization revenues and purchased product expense relate to activities that provide operational flexibility for transportation commitments, product type, delivery points and customer diversification. Revenues and purchased product expense decreased in the second quarter and first six months of 2015 compared to 2014 primarily due to lower commodity prices, partially offset by higher volumes required for optimization.

Corporate and Other

 

 

		Three months ended June 30										Six months ended June 30
($ millions)		2015				2014						2015				2014
Revenues		$	(274	)		$	36					$	(384	)		$	(222)
Expenses
Transportation and processing			(15	)			(2	)					(7	)			(1)
Operating			5				8						11				18
Depreciation, depletion and amortization			25				31						50				62
		$	(289	)		$	(1	)				$	(438	)		$	(301)

Revenues mainly include unrealized hedging gains or losses recorded on derivative financial contracts which result from the volatility in forward curves of commodity prices and changes in the balance of unsettled contracts between periods. Transportation and processing expense reflects unrealized financial hedging gains or losses related to the Company’s power financial derivative contracts. DD&A includes amortization of corporate assets, such as computer equipment, office buildings, furniture and leasehold improvements.

Corporate and Other results include revenues and operating expenses related to the sublease of office space in The Bow office building. Further information on The Bow office sublease can be found in Note 11 to the Interim Condensed Consolidated Financial Statements.

 

MD&A Prepared using U.S. GAAP in US$

---

Q2 Report  |  For the period ended June 30, 2015

 

Other Operating Results

Expenses

 

 

 

		Three months ended June 30										Six months ended June 30
($ millions)		2015				2014						2015				2014
Accretion of asset retirement obligation		$	11			$	13					$	23			$	26
Administrative			84				98						156				200
Interest			278				122						403				269
Foreign exchange (gain) loss, net			(86	)			(172	)					570				52
(Gain) loss on divestitures			(2	)			(204	)					(16	)			(203	)
Other			4				8						5				8
		$	289			$	(135	)				$	1,141			$	352

Administrative expense in the second quarter and first six months of 2015 decreased from 2014 primarily due to lower long-term compensation costs due to the decrease in the Encana share price and the lower U.S./Canadian dollar exchange rate, partially offset by higher restructuring costs. During the second quarter of 2015, Encana revised its plans to align the organizational structure in continued support of the Company’s strategy, which resulted in restructuring costs of $15 million and $30 million for the second quarter and first six months of 2015, respectively. Restructuring costs attributable to work force reductions associated with the 2013 restructuring were $1 million in the second quarter and first six months of 2015 compared with $7 million and $22 million in the second quarter and first six months of 2014, respectively.

Interest expense in the second quarter and first six months of 2015 increased from 2014 primarily due to a one-time interest payment of approximately $165 million resulting from the early redemption of Encana’s $700 million 5.90 percent notes due December 1, 2017 and C$750 million 5.80 percent medium-term notes due January 18, 2018.

Foreign exchange gains and losses result from the impact of the fluctuations in the Canadian to U.S. dollar exchange rate. In the second quarter of 2015 compared to 2014, the Company recorded higher foreign exchange losses on settlements and lower foreign exchange gains on the translation of U.S. dollar long-term debt issued from Canada, partially offset by foreign exchange gains on the translation of intercompany notes. In the first six months of 2015 compared to 2014, Encana recorded higher foreign exchange losses on the translation of U.S. dollar long-term debt issued from Canada and on settlements.

Gain on divestitures in the first six months of 2015 primarily includes a gain on the sale of the Encana Place office building in Calgary. Gain on divestitures in the second quarter and first six months of 2014 primarily includes the before tax impact of the sale of the Jonah properties, as discussed in the Net Capital Investment section of this MD&A.

 

 

		MD&A Prepared using U.S. GAAP in US$

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Q2 Report  |  For the period ended June 30, 2015

 

Income Tax

 

 

		Three months ended June 30										Six months ended June 30
($ millions)			2015				2014						2015				2014
Current Income Tax (Recovery)		$	(35)			$	(19)					$	(19)			$	(3)
Deferred Income Tax (Recovery)			(903)				308						(1,866)				320
Income Tax Expense (Recovery)		$	(938)			$	289					$	(1,885)			$	317

Total income tax recovery in the first six months of 2015 was primarily due to lower net earnings before tax. The net earnings variances are discussed in the Financial Results section of this MD&A.

Encana’s interim income tax expense is determined using the estimated annual effective income tax rate applied to year-to-date net earnings before tax plus the effect of legislative changes, including the 2015 Alberta general corporate income tax rate increase, and amounts in respect of prior periods. The Company’s effective tax rate for the first six months of 2015 is lower than 2014 primarily as a result of changes in expected annual earnings and income tax expense recognized on the sale of a noncontrolling interest in PrairieSky in the second quarter of 2014. The estimated annual effective income tax rate is impacted by expected annual earnings, statutory rate and other foreign differences, non-taxable capital gains and losses, tax differences on divestitures and transactions, and partnership tax allocations in excess of funding.

Tax interpretations, regulations and legislation in the various jurisdictions in which the Company and its subsidiaries operate are subject to change. As a result, there are tax matters under review. The Company believes that the provision for taxes is adequate.

 

Liquidity and Capital Resources

 

		Three months ended June 30										Six months ended June 30
($ millions)			2015				2014						2015				2014
Net Cash From (Used In)
Operating activities		$	298			$	767					$	780			$	1,710
Investing activities			(681)				(1,489)						(413)				(1,935)
Financing activities			(1,170)				1,171						(202)				326
Foreign exchange gain (loss) on cash and cash equivalents held in foreign currency			19				47						(7)				(9)
Increase (Decrease) in Cash and Cash Equivalents		$	(1,534)			$	496					$	158			$	92
Cash and Cash Equivalents, End of Period		$	496			$	2,658					$	496			$	2,658

Operating Activities

 

Net cash from operating activities in the second quarter of 2015 of $298 million decreased $469 million from 2014. These changes are primarily a result of the Cash Flow variances discussed in the Financial Results section of this MD&A. In the second quarter of 2015, the net change in non-cash working capital was a surplus of $110 million compared to $119 million in 2014.

Net cash from operating activities in the first six months of 2015 of $780 million decreased $930 million from 2014. These changes are primarily a result of the Cash Flow variances discussed in the Financial Results section of this MD&A. In the first six months of 2015, the net change in non-cash working capital was a surplus of $104 million compared to a deficit of $23 million in 2014.

 

MD&A Prepared using U.S. GAAP in US$

---

Q2 Report  |  For the period ended June 30, 2015

 

The Company had a working capital surplus of $290 million at June 30, 2015 compared to $455 million at December 31, 2014. The decrease in working capital is primarily due to a decrease in accounts receivable and accrued revenues, a decrease in risk management assets and a decrease in income tax receivable, partially offset by a decrease in accounts payable and accrued liabilities, an increase in cash and cash equivalents, an increase in deferred income tax assets and a decrease in deferred income tax liabilities. At June 30, 2015, working capital included cash and cash equivalents of $496 million compared to $338 million at December 31, 2014. Encana expects that it will continue to meet the payment terms of its suppliers.

Investing Activities

 

Net cash used in investing activities in the first six months of 2015 was $413 million compared to $1,935 million in 2014. The decrease was primarily due to the acquisition of Eagle Ford in 2014, partially offset by lower proceeds from divestitures. Further information on acquisitions and divestitures can be found in the Net Capital Investment section of this MD&A.

Financing Activities

 

Net cash used in financing activities in the first six months of 2015 was $202 million compared to net cash from financing activities of $326 million in 2014. The change was primarily due to the sale of a noncontrolling interest in PrairieSky in the second quarter of 2014, partially offset by proceeds from the issuance of common shares pursuant to the Share Offering in the first quarter of 2015.

Credit Facilities

The following table outlines the Company’s committed revolving bank credit facilities at June 30, 2015:

 

($ billions)

Capacity

Unused

Maturity Date

Committed Revolving Bank Credit Facilities

Encana Credit Facility (1), (2)

2.8

1.4

June 2018

U.S. Subsidiary Credit Facility

1.0

1.0

June 2018

 

(1)	The Encana Credit Facility is Canadian dollar denominated with a capacity of C$3.5 billion.

(2)	At June 30, 2015, $1.4 billion was fully supporting the U.S. Commercial Paper Program, as discussed in the Long-Term Debt section below.

On July 16, 2015, the Company changed its Encana Credit Facility from Canadian dollars to U.S. dollars and amended the capacity to $3.0 billion. The Company also amended the capacity of its U.S. subsidiary Credit Facility to $1.5 billion. The maturity date for both Credit Facilities was extended to July 2020 and $3.1 billion remained unused at July 16, 2015.

Encana is currently in compliance with, and expects that it will continue to be in compliance with, all financial covenants under its credit facility agreements. Management monitors Debt to Adjusted Capitalization as a proxy for Encana’s financial covenant under its credit facility agreements which require debt to adjusted capitalization to be less than 60 percent. The definitions used in the covenant under the credit facilities adjust capitalization for cumulative historical ceiling test impairments that were recorded as at December 31, 2011 in conjunction with the Company’s January 1, 2012 adoption of U.S. GAAP. Debt to Adjusted Capitalization was 28 percent at June 30, 2015 and 30 percent at December 31, 2014.

Long-Term Debt

Encana’s long-term debt, excluding the current portion, totaled $6,112 million at June 30, 2015 and $7,340 million at December 31, 2014. There was no current portion of long-term debt outstanding at June 30, 2015 or December 31, 2014.

On April 6, 2015, the Company used the net proceeds from the Share Offering and cash on hand to complete the redemption of its $700 million 5.90 percent notes due December 1, 2017 and its C$750 million 5.80 percent

 

		MD&A Prepared using U.S. GAAP in US$

---

Q2 Report  |  For the period ended June 30, 2015

 

medium-term notes due January 18, 2018. The note redemptions required an aggregate one-time early interest payment of approximately $165 million and is expected to save Encana a gross amount of approximately $205 million in future interest expense, based on foreign exchange and treasury rates at the time of the redemption.

During the first quarter of 2015, Encana implemented a U.S. Commercial Paper (“U.S. CP”) program which is fully supported by the Company’s revolving credit facility. At June 30, 2015, Encana had an outstanding balance of $1,397 million which reflected U.S. CP issuances that had an average term of 45 days and a weighted average interest rate of 0.66 percent. Management expects these amounts will continue to be supported by the revolving credit facility that has no repayment requirements within the next year. At December 31, 2014, Encana had an outstanding balance of $1,277 million under the Company’s revolving credit facility, which reflected principal obligations related to LIBOR loans maturing at various dates with a weighted average interest rate of 1.62 percent. During the first quarter of 2015, Encana repaid the outstanding balance relating to LIBOR loans using proceeds from the U.S. CP program and cash on hand.

Encana has the flexibility to refinance maturing long-term debt or repay debt maturities from existing sources of liquidity. Encana’s primary sources of liquidity include cash and cash equivalents, revolving bank credit facilities, working capital, operating cash flow and proceeds from asset divestitures.

Shelf Prospectus

On June 27, 2014, Encana filed a short form base shelf prospectus, whereby the Company may issue from time to time up to $6.0 billion, or the equivalent in foreign currencies, of debt securities, common shares, preferred shares, subscription receipts, warrants and units in Canada and/or the U.S. On March 5, 2015, the Company filed a prospectus supplement to the base shelf prospectus for the issuance of 85,616,500 common shares of Encana and granted an over-allotment option for up to an additional 12,842,475 common shares of Encana at a price of C$14.60 per common share, pursuant to an underwriting agreement. The Share Offering of 98,458,975 common shares of Encana was completed during March 2015 for aggregate gross proceeds of approximately C$1.44 billion ($1.13 billion). After deducting underwriter’s fees and costs of the Share Offering, the net proceeds received were approximately C$1.39 billion ($1.09 billion). At June 30, 2015, $4.9 billion, or the equivalent in foreign currencies, remained accessible under the shelf prospectus, the availability of which is dependent upon market conditions. The shelf prospectus expires in July 2016.

Outstanding Share Data

 

(millions)		December 31, 2014				June 30, 2015				July 17, 2015
Common Shares Outstanding			741.2				842.5				842.5
Stock Options with TSARs attached (1)
Outstanding			21.3				20.3				20.2
Exercisable			10.0				11.2				11.1

 

(1)	A Tandem Stock Appreciation Right (“TSAR”) gives the option holder the right to receive a cash payment equal to the excess of the market price of Encana’s common shares at the time of exercise over the original grant price.

During the first quarter of 2015, Encana issued common shares pursuant to the Share Offering as discussed above.

During the first six months of 2015, Encana issued 2,872,237 common shares under the Company’s dividend reinvestment plan (“DRIP”) compared with 113,775 common shares in 2014. The number of common shares issued under the DRIP increased in the first six months of 2015 primarily as a result of Encana’s February 25, 2015 announcement that, effective with the dividend payable on March 31, 2015, any future dividends in conjunction with the DRIP will be issued from its treasury with a two percent discount to the average market price of the common shares unless otherwise announced by the Company via news release.

 

MD&A Prepared using U.S. GAAP in US$

---

Q2 Report  |  For the period ended June 30, 2015

 

Dividends

Encana pays quarterly dividends to shareholders at the discretion of the Board.

 

		Three months ended June 30										Six months ended June 30
($ millions, except as indicated)		2015				2014						2015				2014
Dividend Payments		$	55			$	52					$	107			$	104
Dividend Payments ($/share)			0.07				0.07						0.14				0.14

The dividends paid in the second quarter and first six months of 2015 included $18 million and $32 million, respectively, in common shares issued in lieu of cash dividends under the DRIP compared to $2 million and $3 million, respectively, for 2014. Common shares issued in the Share Offering were not eligible to receive the dividend that was paid during the first quarter of 2015.

On July 23, 2015, the Board declared a dividend of $0.07 per share payable on September 30, 2015 to common shareholders of record as of September 15, 2015.

Capital Structure

The Company’s capital structure consists of total shareholders’ equity plus long-term debt, including the current portion. The Company’s objectives when managing its capital structure are to maintain financial flexibility to preserve Encana’s access to capital markets and its ability to meet financial obligations and finance internally generated growth, as well as potential acquisitions. Encana has a long-standing practice of maintaining capital discipline and managing and adjusting its capital structure according to market conditions to maintain flexibility while achieving the Company’s objectives.

To manage the capital structure, the Company may adjust capital spending, adjust dividends paid to shareholders, issue new shares, issue new debt or repay existing debt. In managing its capital structure, the Company monitors the following non-GAAP financial metrics as indicators of its overall financial strength, which are defined in the Non-GAAP Measures section of this MD&A.

 

		June 30, 2015				December 31, 2014
Debt to Debt Adjusted Cash Flow			2.5x				2.1x
Debt to Adjusted Capitalization			28%				30%

 

		MD&A Prepared using U.S. GAAP in US$

---

Q2 Report  |  For the period ended June 30, 2015

 

Commitments and Contingencies

Commitments

The following table outlines the Company’s commitments at June 30, 2015:

 

		Expected Future Payments
($ millions, undiscounted)		2015				2016				2017				2018				2019				Thereafter				Total
Transportation and Processing		$	427			$	817			$	800			$	816			$	697			$	3,253			$	6,810
Drilling and Field Services			125				136				102				51				15				16				445
Operating Leases			18				30				25				24				11				24				132
Commitments		$	570			$	983			$	927			$	891			$	723			$	3,293			$	7,387

In addition to the Commitments disclosed above, Encana has significant development commitments with joint venture partners, a portion of which may be satisfied by the Drilling and Field Services commitments included in the table above.

Included in Transportation and Processing in the table above are certain commitments associated with midstream service agreements with VMLP. Additional information can be found in Note 16 to the Interim Condensed Consolidated Financial Statements.

Further to the Commitments disclosed above, Encana also has obligations related to its risk management program and to fund its defined benefit pension and other post-employment benefit plans. Further information can be found in Note 21 to the Interim Condensed Consolidated Financial Statements regarding the Company’s risk management program.

Contractual obligations arising from long-term debt, asset retirement obligations, The Bow office building and capital leases are recognized on the Company’s balance sheet. Further information can be found in the note disclosures to the Interim Condensed Consolidated Financial Statements.

The Company expects to fund its 2015 commitments and obligations from Cash Flow and cash and cash equivalents.

Contingencies

Encana is involved in various legal claims and actions arising in the course of the Company’s operations. Although the outcome of these claims cannot be predicted with certainty, the Company does not expect these matters to have a material adverse effect on Encana’s financial position, cash flows or results of operations. If an unfavourable outcome were to occur, there exists the possibility of a material adverse impact on the Company’s consolidated net earnings or loss in the period in which the outcome is determined. Accruals for litigation and claims are recognized if the Company determines that the loss is probable and the amount can be reasonably estimated. The Company believes it has made adequate provision for such legal claims.

 

MD&A Prepared using U.S. GAAP in US$

---

Q2 Report  |  For the period ended June 30, 2015

 

Risk Management

Encana’s business, prospects, financial condition, results of operations and cash flows, and in some cases its reputation, are impacted by risks that can be categorized as follows:

 

•

financial risks;

 

•

operational risks; and

 

•

environmental, regulatory, reputational and safety risks.

Encana aims to strengthen its position as a leading North American energy producer and grow shareholder value through a disciplined focus on generating profitable growth. Encana continues to focus on developing a balanced portfolio of low-risk and low-cost long-life plays, which allows the Company to respond well to market uncertainties. Management adjusts financial and operational risk strategies to proactively respond to changing economic conditions and to mitigate or reduce risk.

Issues that can affect Encana’s reputation are generally strategic or emerging issues that can be identified early and then appropriately managed, but can also include unforeseen issues that must be managed on a more urgent basis. Encana takes a proactive approach to the identification and management of issues that affect the Company’s reputation and has established appropriate policies, procedures, guidelines and responsibilities for identifying and managing these issues.

Financial Risks

Encana defines financial risks as the risk of loss or lost opportunity resulting from financial management and market conditions that could have an impact on Encana’s business.

Financial risks include, but are not limited to:

 

•

market pricing of natural gas and liquids;

 

•

credit and liquidity;

 

•

foreign exchange rates; and

 

•

interest rates.

Encana partially mitigates its exposure to financial risks through the use of various financial instruments and physical contracts. The use of derivative financial instruments is governed under formal policies and is subject to limits established by the Board. All derivative financial agreements are with major global financial institutions or with corporate counterparties having investment grade credit ratings. Encana has in place policies and procedures with respect to the required documentation and approvals for the use of derivative financial instruments and specifically ties their use to the mitigation of financial risk in order to support capital plans and strategic objectives.

To partially mitigate commodity price risk, the Company may enter into transactions that fix, set a floor or set a floor and cap on prices. To help protect against regional price differentials, Encana executes transactions to manage the price differentials between its production areas and various sales points. Further information, including the details of Encana’s financial instruments as at June 30, 2015, is disclosed in Note 21 to the Interim Condensed Consolidated Financial Statements.

Counterparty credit risks are regularly and proactively managed. A substantial portion of Encana’s credit exposure is with customers in the oil and gas industry or financial institutions. This credit exposure is mitigated through the use of Board-approved credit policies governing the Company’s credit portfolio, including credit practices that limit transactions and grant payment terms according to industry standards and counterparties’ credit quality.

The Company manages liquidity risk using cash and debt management programs. The Company has access to cash equivalents and a range of funding alternatives at competitive rates through committed revolving bank credit

 

		MD&A Prepared using U.S. GAAP in US$

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Q2 Report  |  For the period ended June 30, 2015

 

facilities and debt and equity capital markets. Encana closely monitors the Company’s ability to access cost-effective credit and ensures that sufficient liquidity is in place to fund capital expenditures and dividend payments. The Company minimizes its liquidity risk by managing its capital structure which may include adjusting capital spending, adjusting dividends paid to shareholders, issuing new shares, issuing new debt or repaying existing debt.

Operational Risks

Operational risks are defined as the risk of loss or lost opportunity resulting from the following:

 

•

operating activities;

 

•

capital activities, including the ability to complete projects; and

 

•

reserves and resources replacement.

The Company’s ability to operate, generate cash flows, complete projects, and value reserves and resources is subject to financial risks, including commodity prices mentioned above, continued market demand for its products and other risk factors outside of its control. These factors include: general business and market conditions; economic recessions and financial market turmoil; the overall state of the capital markets, including investor appetite for investments in the oil and gas industry generally and the Company’s securities in particular; the ability to secure and maintain cost-effective financing for its commitments; legislative, environmental and regulatory matters; unexpected cost increases; royalties; taxes; volatility in natural gas and liquids prices; partner funding for their share of joint venture and partnership commitments; the availability of drilling and other equipment; the ability to access lands; the ability to access water for hydraulic fracturing operations; weather; the availability of processing capacity; the availability and proximity of take-away capacity; technology failures; the ability to integrate new assets; cyber-attacks; accidents; the availability of skilled labour; and reservoir quality. If Encana fails to acquire or find additional natural gas and liquids reserves and resources, its reserves, resources and production will decline materially from their current levels and, therefore, its cash flows are highly dependent upon successfully exploiting current reserves and resources and acquiring, discovering or developing additional reserves and resources. To mitigate these risks, as part of the capital approval process, the Company’s projects are evaluated on a fully risked basis, including geological risk, engineering risk and reliance on third party service providers.

When making operating and investing decisions, Encana’s highly disciplined, dynamic and centrally controlled capital allocation program ensures investment dollars are directed in a manner that is consistent with the Company’s strategy. Encana also mitigates operational risks through a number of other policies, systems and processes as well as by maintaining a comprehensive insurance program.

In June 2015, the Alberta Government announced that it had appointed a chairman who will form a panel to undertake a review of the province’s oil and gas royalty structure. The panel is expected to consult with industry, the public and stakeholders and report back to the Alberta Government by the end of 2015. Over the coming months, Encana will monitor the work of the panel and engage in the consultations. The Company will assess the impact of possible changes to the royalty structure on its operations as information becomes available.

 

MD&A Prepared using U.S. GAAP in US$

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Q2 Report  |  For the period ended June 30, 2015

 

Environmental, Regulatory, Reputational and Safety Risks

The Company is committed to safety in its operations and has high regard for the environment and stakeholders, including the public and regulators. The Company’s business is subject to all of the operating risks normally associated with the exploration for, development of and production of natural gas, oil and NGLs and the operation of midstream facilities. When assessing the materiality of environmental risk factors, Encana takes into account a number of qualitative and quantitative factors, including, but not limited to, the financial, operational, reputational and regulatory aspects of each identified risk factor. These risks are managed by executing policies and standards that are designed to comply with or exceed government regulations and industry standards. In addition, Encana maintains a system that identifies, assesses and controls safety, security and environmental risk and requires regular reporting to the Executive Leadership Team and the Board. The Corporate Responsibility, Environment, Health and Safety Committee of Encana’s Board provides recommended environmental policies for approval by Encana’s Board and oversees compliance with government laws and regulations. Monitoring and reporting programs for environmental, health and safety performance in day-to-day operations, as well as inspections and audits, are designed to provide assurance that environmental and regulatory standards are met. Emergency response plans are in place to provide guidance during times of crisis. Contingency plans are in place for a timely response to environmental events and remediation/reclamation strategies are utilized to restore the environment.

Encana’s operations are subject to regulation and intervention by governments that can affect or prohibit the drilling, completion, including hydraulic fracturing and tie-in of wells, production, the construction or expansion of facilities and the operation and abandonment of fields. Changes in government regulation could impact the Company’s existing and planned projects as well as impose a cost of compliance.

In the state of Colorado, several cities have passed local ordinances limiting or banning certain oil and gas activities, including hydraulic fracturing. These local rule-making initiatives have not significantly impacted the Company’s operations or development plans in the state to date. Encana continues to work with state and local governments, academics and industry leaders to respond to hydraulic fracturing related concerns in Colorado. The Company recognizes that additional hydraulic fracturing ballot and/or local rule-making limiting or restricting oil and gas development activities are a possibility in the future and will continue to monitor and respond to these developments in 2015.

The U.S. federal government has noted climate change action as a priority for the current administration. On January 14, 2015, the Environmental Protection Agency (“EPA”) outlined a series of steps to address methane and volatile organic compound emissions from the oil and gas industry, including a new goal to reduce oil and gas methane emissions by 40 to 45 percent from 2012 levels by 2025. The reductions will be achieved through regulatory and voluntary measures which have not yet been announced. The EPA plans to propose this new rule and guidance in late summer 2015 with a final rule and guidance expected in 2016.

On June 25, 2015 the Alberta Government announced that it was renewing and updating the Specified Gas Emitters Regulation (the “Regulation”), which governs carbon emissions and was set to expire on June 30, 2015. The Regulation requires any facility that emits 100,000 tonnes or more of greenhouse gases per year to reduce their emissions intensity. The renewed Regulation increases the reduction target from 12 percent to 20 percent by 2017 and increases the cost of carbon from C$15 per tonne to C$30 per tonne by 2017 for those facilities that are unable to meet the specified reduction targets. Encana does not own or operate any facilities which exceed the 100,000 tonne threshold and, as a result, is not currently subject to the Regulation.

In addition to the renewal of the Regulation, the Alberta Government also announced the formation of an advisory panel that will comprehensively review Alberta’s climate change policy, consult stakeholders and provide advice on a permanent set of measures. The panel is expected to conduct stakeholder consultations during the summer of 2015 and will report back to the Alberta Government in the fall. Over the coming months, Encana will monitor the work of the advisory panel and engage in the consultations as appropriate.

A comprehensive discussion of Encana’s risk management is provided in the Company’s annual MD&A for the year ended December 31, 2014.

 

		MD&A Prepared using U.S. GAAP in US$

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Q2 Report  |  For the period ended June 30, 2015

 

Controls and Procedures

Internal Control over Financial Reporting

Management is responsible for establishing and maintaining adequate internal control over the Company’s financial reporting, which is a process designed by, or designed under the supervision of the Chief Executive Officer and Chief Financial Officer, and effected by the Board, Management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with U.S. GAAP.

Encana previously limited the scope and design and subsequent evaluation of internal controls over financial reporting to exclude the controls, policies and procedures of Athlon Energy Inc., acquired through a business combination on November 13, 2014. During the second quarter of 2015, the Company completed the evaluation and integration of the controls, policies and procedures of Athlon Energy Inc. No material weaknesses or significant deficiencies were noted during the integration and there have been no other changes to the Company’s internal control over financial reporting during the three months ended June 30, 2015 that have materially affected, or are reasonably likely to materially affect, the effectiveness of the internal control over financial reporting.

Limitations of the Effectiveness of Controls

The Company’s control system was designed to provide reasonable assurance to Management regarding the preparation and presentation of the Consolidated Financial Statements. Control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation and should not be expected to prevent all errors or fraud. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

 

MD&A Prepared using U.S. GAAP in US$

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Q2 Report  |  For the period ended June 30, 2015

 

Accounting Policies and Estimates

Critical Accounting Estimates

 

Refer to the annual MD&A for the year ended December 31, 2014 for a comprehensive discussion of Encana’s Critical Accounting Policies and Estimates.

Recent Accounting Pronouncements

 

Changes in Accounting Policies and Practices

On January 1, 2015, Encana adopted Accounting Standard Update (“ASU”) 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity as issued by the Financial Accounting Standards Board (“FASB”). The update amends the criteria and expands the disclosures for reporting discontinued operations. Under the new criteria, only disposals representing a strategic shift in operations would qualify as a discontinued operation. The amendments have been applied prospectively and have not had a material impact on the Company’s Interim Condensed Consolidated Financial Statements.

New Standards Issued Not Yet Adopted

As of January 1, 2016, Encana will be required to adopt the following pronouncements issued by the FASB:

 

•

ASU 2014-12, Compensation – Stock Compensation: Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved After the Requisite Service Period. The update requires that a performance target that affects vesting and could be achieved after the requisite service period be treated as a performance condition. The amendments will be applied prospectively and are not expected to have a material impact on the Company’s Consolidated Financial Statements.

 

•

ASU 2015-02, Amendments to the Consolidation Analysis. The update requires limited partnerships and similar entities to be evaluated under the variable interest and voting interest models, eliminate the presumption that a general partner should consolidate a limited partnership, and simplify the identification of variable interests and related effect on the primary beneficiary criterion when fees are paid to a decision maker. The amendments can be applied using either a full retrospective approach or a modified retrospective approach at the date of adoption. Encana is currently assessing the potential impact of the amendments on the Company’s Consolidated Financial Statements.

 

•

ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs. The update requires debt issuance costs to be presented on the balance sheet as a deduction from the carrying amount of the related liability. Previously, debt issuance costs were presented as a deferred charge within assets. The amendments will be applied retrospectively. As at June 30, 2015, $34 million of debt issuance costs were presented in Other Assets on the Company’s interim Condensed Consolidated Balance Sheet ($39 million as at December 31, 2014).

As of January 1, 2017, Encana will be required to adopt ASU 2014-09, Revenue from Contracts with Customers under Topic 606, which was the result of a joint project by the FASB and International Accounting Standards Board. The new standard replaces Topic 605, Revenue Recognition, and other industry-specific guidance in the Accounting Standards Codification. The new standard is based on the principle that revenue is recognized on the transfer of promised goods or services to customers in an amount that reflects the consideration the Company expects to be entitled to in exchange for those goods or services. The standard can be applied using either the full retrospective approach or a modified retrospective approach at the date of adoption. Encana is currently assessing the potential impact of the standard on the Company’s Consolidated Financial Statements.

 

		MD&A Prepared using U.S. GAAP in US$

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Q2 Report  |  For the period ended June 30, 2015

 

Non-GAAP Measures

Certain measures in this document do not have any standardized meaning as prescribed by U.S. GAAP and, therefore, are considered non-GAAP measures. These measures may not be comparable to similar measures presented by other issuers. These measures are commonly used in the oil and gas industry and by Encana to provide shareholders and potential investors with additional information regarding the Company’s liquidity and its ability to generate funds to finance its operations. Non-GAAP measures include: Cash Flow; Free Cash Flow; Operating Earnings (Loss); Upstream Operating Cash Flow, excluding Hedging; Operating Netback; Debt to Debt Adjusted Cash Flow; and Debt to Adjusted Capitalization. Management’s use of these measures is discussed further below.

Cash Flow and Free Cash Flow

 

Cash Flow is a non-GAAP measure commonly used in the oil and gas industry and by Encana to assist Management and investors in measuring the Company’s ability to finance capital programs and meet financial obligations. Cash Flow is defined as cash from operating activities excluding net change in other assets and liabilities, net change in non-cash working capital and cash tax on sale of assets.

Free Cash Flow is a non-GAAP measure defined as Cash Flow in excess of capital investment, excluding net acquisitions and divestitures, and is used to determine the funds available for other investing and/or financing activities.

 

		Six months ended June 30										2015										2014																		2013
($ millions)			2015				2014						Q2				Q1						Q4				Q3				Q2				Q1						Q4				Q3
Cash From (Used in) Operating Activities		$	780			$	1,710					$	298			$	482					$	261			$	696			$	767			$	943					$	462			$	935
(Add back) deduct:
Net change in other assets and liabilities			-				(17	)					7				(7	)					(15	)			(11	)			(8	)			(9	)					(21	)			(15	)
Net change in non-cash working capital			104				(23	)					110				(6	)					(141	)			155				119				(142	)					(183	)			300
Cash tax on sale of assets			-				-						-				-						40				(255	)			-				-						(11	)			(10	)
Cash Flow		$	676			$	1,750					$	181			$	495					$	377			$	807			$	656			$	1,094					$	677			$	660
Deduct:
Capital investment			1,479				1,071						743				736						857				598				560				511						717				641
Free Cash Flow		$	(803	)		$	679					$	(562	)		$	(241	)				$	(480)			$	209			$	96			$	583					$	(40)			$	19

 

MD&A Prepared using U.S. GAAP in US$

---

Q2 Report  |  For the period ended June 30, 2015

 

Operating Earnings

 

Operating Earnings (Loss) is a non-GAAP measure that adjusts Net Earnings (Loss) Attributable to Common Shareholders by non-operating items that Management believes reduces the comparability of the Company’s underlying financial performance between periods. Operating Earnings (Loss) is commonly used in the oil and gas industry and by Encana to provide investors with information that is more comparable between periods.

Operating Earnings (Loss) is defined as Net Earnings (Loss) Attributable to Common Shareholders excluding non-recurring or non-cash items that Management believes reduces the comparability of the Company’s financial performance between periods. These after-tax items may include, but are not limited to, unrealized hedging gains/losses, impairments, restructuring charges, non-operating foreign exchange gains/losses, gains/losses on divestitures, income taxes related to divestitures and adjustments to normalize the effect of income taxes calculated using the estimated annual effective income tax rate.

 

		Six months ended June 30										2015										2014																		2013
($ millions)			2015				2014						Q2				Q1						Q4				Q3				Q2				Q1						Q4				Q3
Net Earnings (Loss) Attributable to Common Shareholders		$	(3,317	)		$	387					$	(1,610	)		$	(1,707	)				$	198			$	2,807			$	271			$	116					$	(251	)		$	188
After-tax (addition) / deduction:
Unrealized hedging gain (loss)			(285	)			(195	)					(187	)			(98	)					341				160				8				(203	)					(209	)			(89	)
Impairments			(2,550	)			-						(1,328	)			(1,222	)					-				-				-				-						-				(16	)
Restructuring charges (1)			(20	)			(15	)					(10	)			(10	)					(4	)			(5	)			(5	)			(10	)					(64	)			-
Non-operating foreign exchange gain (loss)			(394	)			(38	)					114				(508	)					(151	)			(218	)			156				(194	)					(124	)			105
Gain (loss) on divestitures			11				135						1				10						(11	)			2,399				135				-						-				-
Income tax adjustments			69				(186	)					(33	)			102						(12	)			190				(194	)			8						(80	)			38
Operating Earnings (Loss) (1)		$	(148	)		$	686					$	(167	)		$	19					$	35			$	281			$	171			$	515					$	226			$	150

 

(1)	In continued support of Encana’s strategy, organizational structure changes were formalized in Q2 2015 and resulted in a revision to the Q1 2015 Operating Earnings to exclude restructuring charges incurred in the first quarter.

 

		MD&A Prepared using U.S. GAAP in US$

---

Q2 Report  |  For the period ended June 30, 2015

 

Upstream Operating Cash Flow, excluding Hedging

 

Upstream Operating Cash Flow, excluding Hedging is a non-GAAP measure that adjusts the Canadian and USA Operations revenues, net of royalties for production and mineral taxes, transportation and processing expense, operating expense and the impacts of realized hedging. Management monitors Upstream Operating Cash Flow, excluding Hedging as it reflects operating performance and measures the Company’s portfolio transition to higher margin production. Upstream Operating Cash Flow, excluding Hedging is reconciled to GAAP measures in the Results of Operations section of this MD&A. The table below totals Upstream Operating Cash Flow for Encana.

 

		Six months ended June 30										2015										2014																		2013
($ millions)			2015				2014						Q2				Q1						Q4				Q3				Q2				Q1						Q4				Q3
Upstream Operating Cash Flow
Canadian Operations		$	584			$	1,328					$	171			$	413					$	341			$	477			$	447			$	881					$	526			$	406
USA Operations			597				787						308				289						480				505				353				434						375				388
		$	1,181			$	2,115					$	479			$	702					$	821			$	982			$	800			$	1,315					$	901			$	794
(Add back) deduct:
Realized Hedging Gain (Loss)
Canadian Operations		$	257			$	(124	)				$	101			$	156					$	49			$	19			$	(49	)		$	(75	)				$	90			$	95
USA Operations			155				(114	)					63				92						78				11				(49	)			(65	)					83				77
		$	412			$	(238	)				$	164			$	248					$	127			$	30			$	(98	)		$	(140	)				$	173			$	172
Upstream Operating Cash Flow, excluding Hedging
Canadian Operations		$	327			$	1,452					$	70			$	257					$	292			$	458			$	496			$	956					$	436			$	311
USA Operations			442				901						245				197						402				494				402				499						292				311
		$	769			$	2,353					$	315			$	454					$	694			$	952			$	898			$	1,455					$	728			$	622

Operating Netback

 

Operating Netback is a common metric used in the oil and gas industry to measure operating performance by product. Operating Netbacks are calculated by determining product revenues, net of royalties and deducting costs associated with delivering the product to market, including production and mineral taxes, transportation and processing expense and operating expense. The Operating Netback calculation is shown in the Results of Operations section of this MD&A.

 

MD&A Prepared using U.S. GAAP in US$

---

Q2 Report  |  For the period ended June 30, 2015

 

Debt to Debt Adjusted Cash Flow

 

Debt to Debt Adjusted Cash Flow is a non-GAAP measure monitored by Management as an indicator of the Company’s overall financial strength. Debt Adjusted Cash Flow is a non-GAAP measure defined as Cash Flow on a trailing 12-month basis excluding interest expense after tax.

 

($ millions)		June 30, 2015				December 31, 2014
Debt		$	6,112			$	7,340
Cash Flow			1,860				2,934
Interest Expense, after tax			583				486
Debt Adjusted Cash Flow		$	2,443			$	3,420
Debt to Debt Adjusted Cash Flow			2.5x				2.1x

Debt to Adjusted Capitalization

 

Debt to Adjusted Capitalization is a non-GAAP measure which adjusts capitalization for historical ceiling test impairments that were recorded as at December 31, 2011. Management monitors Debt to Adjusted Capitalization as a proxy for Encana’s financial covenant under its credit facility agreements which require debt to adjusted capitalization to be less than 60 percent. Adjusted Capitalization includes debt, total shareholders’ equity and an equity adjustment for cumulative historical ceiling test impairments recorded as at December 31, 2011 in conjunction with the Company’s January 1, 2012 adoption of U.S. GAAP.

 

($ millions)		June 30, 2015				December 31, 2014
Debt		$	6,112			$	7,340
Total Shareholders’ Equity			7,817				9,685
Equity Adjustment for Impairments at December 31, 2011			7,746				7,746
Adjusted Capitalization		$	21,675			$	24,771
Debt to Adjusted Capitalization			28%				30%

 

		MD&A Prepared using U.S. GAAP in US$

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Q2 Report  |  For the period ended June 30, 2015

 

Advisory

Forward-Looking Statements

 

Certain statements contained in this document constitute forward-looking statements or information (collectively, “forward-looking statements”) within the meaning of the “safe harbour” provisions of applicable securities legislation. Forward-looking statements are typically identified by words such as “anticipate”, “believe”, “expect”, “plan”, “intend”, “forecast”, “target”, “project”, “objective”, “strategy”, “strives”, “agreed to” or similar words suggesting future outcomes or statements regarding an outlook. In this document, forward-looking statements include, but are not limited to:

 

 

Readers are cautioned upon unduly relying on forward-looking statements as there can be no assurance that the plans, intentions or expectations upon which they are based will occur. By their nature, these statements involve numerous assumptions, known and unknown risks and uncertainties and other factors, which can contribute to the possibility that such statements will not occur or which may cause the actual performance and financial results of the Company to differ materially from those expressed or implied by such statements. These assumptions include, but are not limited to:

 

 

MD&A Prepared using U.S. GAAP in US$

---

Q2 Report  |  For the period ended June 30, 2015

 

Risks and uncertainties that may affect the operations and development of our business include, but are not limited to: the ability to generate sufficient cash flow to meet the Company’s obligations; commodity price volatility; ability to secure adequate product transportation and potential pipeline curtailments; variability of dividends to be paid; the timing and costs of well, facilities and pipeline construction; business interruption and casualty losses or unexpected technical difficulties; counterparty and credit risk; risk and effect of a downgrade in credit rating, including access to capital markets; fluctuations in currency and interest rates; assumptions based upon the Company’s 2015 corporate guidance; failure to achieve anticipated results from cost and efficiency initiatives; risks inherent in marketing operations; risks associated with technology; the Company’s ability to acquire or find additional reserves; imprecision of reserves estimates and estimates of recoverable quantities of natural gas and liquids from resource plays and other sources not currently classified as proved, probable or possible reserves or economic contingent resources, including future net revenue estimates; risks associated with past and future divestitures of certain assets or other transactions or receive amounts contemplated under the transaction agreements (such transactions may include third-party capital investments, farm-outs or partnerships, which Encana may refer to from time to time as “partnerships” or “joint ventures” and the funds received in respect thereof which Encana may refer to from time to time as “proceeds”, “deferred purchase price” and/or “carry capital”, regardless of the legal form) as a result of various conditions not being met; and other risks and uncertainties impacting Encana’s business as described from time to time in Encana’s annual MD&A, financial statements, Annual Information Form and Form 40-F, as filed on SEDAR and EDGAR.

Although Encana believes that the expectations represented by such forward-looking statements are reasonable, there can be no assurance that such expectations will prove to be correct. Readers are cautioned that the assumptions, risks and uncertainties referenced above are not exhaustive. The forward-looking statements contained in this document are made as of the date of this document and, except as required by law, Encana undertakes no obligation to update publicly or revise any forward-looking statements. The forward-looking statements contained in this document are expressly qualified by these cautionary statements.

Encana is required to disclose events and circumstances that occurred during the period to which this MD&A relates that are reasonably likely to cause actual results to differ materially from material forward-looking statements for a period that is not yet complete that Encana has previously disclosed to the public and the expected differences thereto. Such disclosure can be found in Encana’s news release dated July 24, 2015, which is available on Encana’s website at www.encana.com, on SEDAR at www.sedar.com and EDGAR at www.sec.gov.

 

		MD&A Prepared using U.S. GAAP in US$

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Q2 Report  |  For the period ended June 30, 2015

 

Oil and Gas Information

 

National Instrument 51-101 (“NI 51-101”) of the Canadian Securities Administrators imposes oil and gas disclosure standards for Canadian public companies engaged in oil and gas activities. The Canadian protocol disclosure is contained in Appendix A and under “Narrative Description of the Business” in the Company’s Annual Information Form (“AIF”). Encana obtained an exemption dated January 4, 2011 from certain requirements of NI 51-101 to permit it to provide certain disclosure prepared in accordance with U.S. disclosure requirements, in addition to the Canadian protocol disclosure. The Company’s U.S. protocol disclosure is included in Note 26 (unaudited) to the Company’s Consolidated Financial Statements for the year ended December 31, 2014 and in Appendix D of the AIF.

Further, Encana obtained an exemption dated January 21, 2015 from certain requirements of NI 51-101 to permit it to use the definition of “product type” contained in the amendments to NI 51-101, published by the securities regulatory authority in each of the jurisdictions of Canada on December 4, 2014 that came into force on July 1, 2015, as it relates to its Canadian protocol disclosure contained in Appendix A of the AIF.

A description of the primary differences between the disclosure requirements under the Canadian standards and under the U.S. standards is set forth under the heading “Reserves and Other Oil and Gas Information” in the AIF.

Natural Gas, Oil and NGLs Conversions

In this document, certain natural gas volumes have been converted to BOE on the basis of six Mcf to one bbl. BOE may be misleading, particularly if used in isolation. A conversion ratio of 6:1 is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent value equivalency at the wellhead.

Given that the value ratio based on the current price of natural gas as compared to oil is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.

Play and Resource Play

Play is a term used by Encana which encompasses resource plays, geological formations and conventional plays. Resource play is a term used by Encana to describe an accumulation of hydrocarbons known to exist over a large areal expanse and/or thick vertical section, which, when compared to a conventional play, typically has a lower geological and/or commercial development risk and lower average decline rate.

Additional Information

 

Further information regarding Encana Corporation, including its AIF, can be accessed under the Company’s public filings found on SEDAR at www.sedar.com, on EDGAR at www.sec.gov and on the Company’s website at www.encana.com.

 

MD&A Prepared using U.S. GAAP in US$

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Q2 Report  |  For the period ended June 30, 2015

 

Condensed Consolidated Statement of Earnings (unaudited)

 

 

						Three Months Ended June 30,								Six Months Ended June 30,
($ millions, except per share amounts)						2015				2014				2015				2014
Revenues, Net of Royalties			(Note 3	)		$	830			$	1,588			$	2,079			$	3,480
Expenses			(Note 3	)
Production and mineral taxes							26				33				45				80
Transportation and processing							300				400				640				779
Operating							209				178				398				367
Purchased product							79				142				200				370
Depreciation, depletion and amortization							394				400				860				818
Impairments			(Note 9	)			2,081				-				3,997				-
Accretion of asset retirement obligation			(Note 12	)			11				13				23				26
Administrative			(Note 17	)			84				98				156				200
Interest			(Note 6	)			278				122				403				269
Foreign exchange (gain) loss, net			(Note 7	)			(86	)			(172	)			570				52
(Gain) loss on divestitures			(Note 5	)			(2	)			(204	)			(16	)			(203	)
Other							4				8				5				8
							3,378				1,018				7,281				2,766
Net Earnings (Loss) Before Income Tax							(2,548	)			570				(5,202	)			714
Income tax expense (recovery)			(Note 8	)			(938	)			289				(1,885	)			317
Net Earnings (Loss)							(1,610	)			281				(3,317	)			397
Net earnings attributable to noncontrolling interest			(Note 15	)			-				(10	)			-				(10	)
Net Earnings (Loss) Attributable to Common Shareholders						$	(1,610	)		$	271			$	(3,317	)		$	387
Net Earnings (Loss) per Common Share
Basic & Diluted			(Note 13	)		$	(1.91	)		$	0.37			$	(4.15	)		$	0.52
Condensed Consolidated Statement of Comprehensive Income (unaudited)
						Three Months Ended June 30,								Six Months Ended June 30,
($ millions)						2015				2014				2015				2014
Net Earnings (Loss)						$	(1,610	)		$	281			$	(3,317	)		$	397
Other Comprehensive Income (Loss), Net of Tax
Foreign currency translation adjustment			(Note 14	)			(53	)			(2	)			425				22
Pension and other post-employment benefit plans			(Notes 14, 19	)			-				-				1				-
Other Comprehensive Income (Loss)							(53	)			(2	)			426				22
Comprehensive Income (Loss)							(1,663	)			279				(2,891	)			419
Comprehensive Income Attributable to Noncontrolling Interest			(Note 15	)			-				(10	)			-				(10	)
Comprehensive Income (Loss) Attributable to Common Shareholders						$	(1,663	)		$	269			$	(2,891	)		$	409

See accompanying Notes to Condensed Consolidated Financial Statements

 

		Condensed Consolidated Financial Statements Prepared in accordance with U.S. GAAP in US$

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Q2 Report  |  For the period ended June 30, 2015

 

Condensed Consolidated Balance Sheet (unaudited)

 

 

($ millions)						As at June 30, 2015				As at December 31, 2014
Assets
Current Assets
Cash and cash equivalents						$	496			$	338
Accounts receivable and accrued revenues							751				1,307
Risk management			(Note 21	)			330				707
Income tax receivable							408				509
Deferred income taxes							112				-
							2,097				2,861
Property, Plant and Equipment, at cost:			(Note 9	)
Natural gas and oil properties, based on full cost accounting
Proved properties							42,084				42,615
Unproved properties							5,855				6,133
Other							2,478				2,711
Property, plant and equipment							50,417				51,459
Less: Accumulated depreciation, depletion and amortization							(37,088	)			(33,444	)
Property, plant and equipment, net			(Note 3	)			13,329				18,015
Cash in Reserve							1				73
Other Assets							366				394
Risk Management			(Note 21	)			11				65
Deferred Income Taxes							377				296
Goodwill			(Notes 3, 4, 5	)			2,862				2,917
			(Note 3	)		$	19,043			$	24,621
Liabilities and Shareholders’ Equity
Current Liabilities
Accounts payable and accrued liabilities						$	1,744			$	2,243
Income tax payable							2				15
Risk management			(Note 21	)			26				20
Deferred income taxes							35				128
							1,807				2,406
Long-Term Debt			(Note 10	)			6,112				7,340
Other Liabilities and Provisions			(Note 11	)			2,268				2,484
Risk Management			(Note 21	)			15				7
Asset Retirement Obligation			(Note 12	)			765				870
Deferred Income Taxes							259				1,829
							11,226				14,936
Commitments and Contingencies			(Note 22	)
Shareholders’ Equity
Share capital - authorized unlimited common shares, without par value 2015 issued and outstanding: 842.5 million shares (2014: 741.2 million shares)			(Note 13	)			3,580				2,450
Paid in surplus			(Notes 15, 18	)			1,358				1,358
Retained earnings							1,764				5,188
Accumulated other comprehensive income			(Note 14	)			1,115				689
Total Shareholders’ Equity							7,817				9,685
						$	19,043			$	24,621

See accompanying Notes to Condensed Consolidated Financial Statements

 

Condensed Consolidated Financial Statements Prepared in accordance with U.S. GAAP in US$

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Q2 Report  |  For the period ended June 30, 2015

 

Condensed Consolidated Statement of Changes in Shareholders’ Equity (unaudited)

 

 

Six Months Ended June 30, 2015 ($ millions)						Share Capital				Paid in Surplus				Retained Earnings				Accumulated Other Comprehensive Income				Non- Controlling Interest				Total Shareholders’ Equity
Balance, December 31, 2014						$	2,450			$	1,358			$	5,188			$	689			$	-			$	9,685
Net Earnings (Loss)							-				-				(3,317)				-				-				(3,317)
Dividends on Common Shares			(Note 13)				-				-				(107)				-				-				(107)
Common Shares Issued			(Note 13)				1,098				-				-				-				-				1,098
Common Shares Issued Under Dividend Reinvestment Plan			(Note 13)				32				-				-				-				-				32
Other Comprehensive Income			(Note 14)				-				-				-				426				-				426
Balance, June 30, 2015						$	3,580			$	1,358			$	1,764			$	1,115			$	-			$	7,817
Six Months Ended June 30, 2014 ($ millions)						Share Capital				Paid in Surplus				Retained Earnings				Accumulated Other Comprehensive Income				Non- Controlling Interest				Total Shareholders’ Equity
Balance, December 31, 2013						$	2,445			$	15			$	2,003			$	684			$	-			$	5,147
Share-Based Compensation			(Note 18)				-				(1)				-				-				-				(1)
Net Earnings							-				-				387				-				10				397
Dividends on Common Shares			(Note 13)				-				-				(104)				-				-				(104)
Common Shares Issued Under Dividend Reinvestment Plan			(Note 13)				3				-				-				-				-				3
Other Comprehensive Income			(Note 14)				-				-				-				22				-				22
Sale of Noncontrolling Interest			(Note 15)				-				1,354				-				-				117				1,471
Distributions to Noncontrolling Interest Owners			(Note 15)				-				-				-				-				(6)				(6)
Balance, June 30, 2014						$	2,448			$	1,368			$	2,286			$	706			$	121			$	6,929

See accompanying Notes to Condensed Consolidated Financial Statements

 

		Condensed Consolidated Financial Statements Prepared in accordance with U.S. GAAP in US$

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Q2 Report  |  For the period ended June 30, 2015

 

Condensed Consolidated Statement of Cash Flows (unaudited)

 

 

						Three Months Ended June 30,								Six Months Ended June 30,
($ millions)						2015				2014				2015				2014
Operating Activities
Net earnings (loss)						$	(1,610	)		$	281			$	(3,317	)		$	397
Depreciation, depletion and amortization							394				400				860				818
Impairments			(Note 9	)			2,081				-				3,997				-
Accretion of asset retirement obligation			(Note 12	)			11				13				23				26
Deferred income taxes			(Note 8	)			(903	)			308				(1,866	)			320
Unrealized (gain) loss on risk management			(Note 21	)			278				(9	)			414				276
Unrealized foreign exchange (gain) loss			(Note 7	)			(245	)			(178	)			314				19
Foreign exchange on settlements			(Note 7	)			137				1				235				27
(Gain) loss on divestitures			(Note 5	)			(2	)			(204	)			(16	)			(203	)
Other							40				44				32				70
Net change in other assets and liabilities							7				(8	)			-				(17	)
Net change in non-cash working capital							110				119				104				(23	)
Cash From (Used in) Operating Activities							298				767				780				1,710
Investing Activities
Capital expenditures			(Note 3	)			(743	)			(560	)			(1,479	)			(1,071	)
Acquisitions			(Note 5	)			(3	)			(2,923	)			(38	)			(2,946	)
Proceeds from divestitures			(Note 5	)			143				2,271				1,016				2,318
Cash in reserve							43				(215	)			72				(212	)
Net change in investments and other							(121	)			(62	)			16				(24	)
Cash From (Used in) Investing Activities							(681	)			(1,489	)			(413	)			(1,935	)
Financing Activities
Net issuance (repayment) of revolving long-term debt							186				-				120				-
Repayment of long-term debt			(Note 10	)			(1,302	)			(232	)			(1,302	)			(1,002	)
Issuance of common shares			(Note 13	)			-				-				1,088				-
Dividends on common shares			(Note 13	)			(37	)			(50	)			(75	)			(101	)
Proceeds from sale of noncontrolling interest			(Note 15	)			-				1,471				-				1,471
Capital lease payments and other financing arrangements			(Note 11	)			(17	)			(18	)			(33	)			(42	)
Cash From (Used in) Financing Activities							(1,170	)			1,171				(202	)			326
Foreign Exchange Gain (Loss) on Cash and Cash Equivalents Held in Foreign Currency							19				47				(7	)			(9	)
Increase (Decrease) in Cash and Cash Equivalents							(1,534	)			496				158				92
Cash and Cash Equivalents, Beginning of Period							2,030				2,162				338				2,566
Cash and Cash Equivalents, End of Period						$	496			$	2,658			$	496			$	2,658
Cash, End of Period						$	86			$	107			$	86			$	107
Cash Equivalents, End of Period							410				2,551				410				2,551
Cash and Cash Equivalents, End of Period						$	496			$	2,658			$	496			$	2,658

See accompanying Notes to Condensed Consolidated Financial Statements

 

Condensed Consolidated Financial Statements Prepared in accordance with U.S. GAAP in US$

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Q2 Report  |  For the period ended June 30, 2015

 

Notes to Condensed Consolidated Financial Statements (unaudited)

 

(All amounts in $ millions unless otherwise specified)

 

1. Basis of Presentation and Principles of Consolidation

Encana Corporation and its subsidiaries (“Encana” or “the Company”) are in the business of the exploration for, the development of, and the production and marketing of natural gas, oil and natural gas liquids (“NGLs”). The term liquids is used to represent Encana’s oil, NGLs and condensate.

The interim Condensed Consolidated Financial Statements include the accounts of Encana and are presented in accordance with accounting principles generally accepted in the United States (“U.S. GAAP”).

The interim Condensed Consolidated Financial Statements include the accounts of Encana and entities in which it holds a controlling interest. The noncontrolling interest represented the third party equity ownership in a former consolidated subsidiary, PrairieSky Royalty Ltd. (“PrairieSky”) as presented in the Condensed Consolidated Statement of Changes in Shareholders’ Equity. See Note 15 for further details regarding the noncontrolling interest. All intercompany balances and transactions are eliminated on consolidation. Undivided interests in natural gas and oil exploration and production joint ventures and partnerships are consolidated on a proportionate basis. Investments in non-controlled entities over which Encana has the ability to exercise significant influence are accounted for using the equity method.

The interim Condensed Consolidated Financial Statements have been prepared following the same accounting policies and methods of computation as the annual audited Consolidated Financial Statements for the year ended December 31, 2014, except as noted below in Note 2. The disclosures provided below are incremental to those included with the annual audited Consolidated Financial Statements. Certain information and disclosures normally required to be included in the notes to the annual audited Consolidated Financial Statements have been condensed or have been disclosed on an annual basis only. Accordingly, the interim Condensed Consolidated Financial Statements should be read in conjunction with the annual audited Consolidated Financial Statements and the notes thereto for the year ended December 31, 2014.

These unaudited interim Condensed Consolidated Financial Statements reflect, in the opinion of Management, all normal and recurring adjustments necessary to present fairly the financial position and results of the Company as at and for the periods presented. Interim condensed consolidated financial results are not necessarily indicative of consolidated financial results expected for the fiscal year.

 

2. Recent Accounting Pronouncements

Changes in Accounting Policies and Practices

On January 1, 2015, Encana adopted Accounting Standards Update (“ASU”) 2014-08, “Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity” as issued by the Financial Accounting Standards Board (“FASB”). The update amends the criteria and expands the disclosures for reporting discontinued operations. Under the new criteria, only disposals representing a strategic shift in operations would qualify as a discontinued operation. The amendments have been applied prospectively and have not had a material impact on the Company’s interim Condensed Consolidated Financial Statements.

 

		Notes to Condensed Consolidated Financial Statements Prepared in accordance with U.S. GAAP in US$

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Q2 Report  |  For the period ended June 30, 2015

 

Notes to Condensed Consolidated Financial Statements  (unaudited)

(All amounts in $ millions unless otherwise specified)

 

2.  Recent Accounting Pronouncements (continued)

 

New Standards Issued Not Yet Adopted

As of January 1, 2016, Encana will be required to adopt the following pronouncements issued by the FASB:

 

●

ASU 2014-12, “Compensation - Stock Compensation: Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved After the Requisite Service Period”. The update requires that a performance target that affects vesting and could be achieved after the requisite service period be treated as a performance condition. The amendments will be applied prospectively and are not expected to have a material impact on the Company’s Consolidated Financial Statements.

 

●

ASU 2015-02, “Amendments to the Consolidation Analysis”. The update requires limited partnerships and similar entities to be evaluated under the variable interest and voting interest models, eliminate the presumption that a general partner should consolidate a limited partnership, and simplify the identification of variable interests and related effect on the primary beneficiary criterion when fees are paid to a decision maker. The amendments can be applied using either a full retrospective approach or a modified retrospective approach at the date of adoption. Encana is currently assessing the potential impact of the amendments on the Company’s Consolidated Financial Statements.

 

●

ASU 2015-03, “Simplifying the Presentation of Debt Issuance Costs”. The update requires debt issuance costs to be presented on the balance sheet as a deduction from the carrying amount of the related liability. Previously, debt issuance costs were presented as a deferred charge within assets. The amendments will be applied retrospectively. As at June 30, 2015, $34 million of debt issuance costs were presented in Other Assets on the Company’s interim Condensed Consolidated Balance Sheet ($39 million as at December 31, 2014).

As of January 1, 2017, Encana will be required to adopt ASU 2014-09, “Revenue from Contracts with Customers” under Topic 606, which was the result of a joint project by the FASB and International Accounting Standards Board. The new standard replaces Topic 605, “Revenue Recognition”, and other industry-specific guidance in the Accounting Standards Codification. The new standard is based on the principle that revenue is recognized on the transfer of promised goods or services to customers in an amount that reflects the consideration the Company expects to be entitled to in exchange for those goods or services. The standard can be applied using either the full retrospective approach or a modified retrospective approach at the date of adoption. Encana is currently assessing the potential impact of the standard on the Company’s Consolidated Financial Statements.

 

3.  Segmented Information

Encana’s reportable segments are determined based on the Company’s operations and geographic locations as follows:

 

●

Canadian Operations includes the exploration for, development of, and production of natural gas, oil and NGLs and other related activities within the Canadian cost centre.

 

●

USA Operations includes the exploration for, development of, and production of natural gas, oil and NGLs and other related activities within the U.S. cost centre.

 

●

Market Optimization is primarily responsible for the sale of the Company’s proprietary production. These results are reported in the Canadian and USA Operations. Market optimization activities include third party purchases and sales of product to provide operational flexibility for transportation commitments, product type, delivery points and customer diversification. These activities are reflected in the Market Optimization segment. Market Optimization sells substantially all of the Company’s upstream production to third party customers. Transactions between segments are based on market values and are eliminated on consolidation.

Corporate and Other mainly includes unrealized gains or losses recorded on derivative financial instruments. Once the instruments are settled, the realized gains and losses are recorded in the reporting segment to which the derivative instruments relate.

 

Notes to Condensed Consolidated Financial Statements Prepared in accordance with U.S. GAAP in US$

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Q2 Report  |  For the period ended June 30, 2015

 

Notes to Condensed Consolidated Financial Statements  (unaudited)

(All amounts in $ millions unless otherwise specified)

 

3.  Segmented Information (continued)

 

Results of Operations (For the three months ended June 30)

Segment and Geographic Information

 

		Canadian Operations						USA Operations								Market Optimization
		2015		2014				2015				2014				2015				2014
Revenues, Net of Royalties		$            387		$	754			$	629			$	638			$	88			$	160
Expenses
Production and mineral taxes		-			4				26				29				-				-
Transportation and processing		171			225				144				177				-				-
Operating		45			78				151				79				8				13
Purchased product		-			-				-				-				79				142
		171			447				308				353				1				5
Depreciation, depletion and amortization		68			165				301				203				-				1
Impairments		-			-				2,081				-				-				-
		$            103		$	282			$	(2,074	)		$	150			$	1			$	4
								Corporate & Other								Consolidated
								2015				2014				2015				2014
Revenues, Net of Royalties								$	(274	)		$	36			$	830			$	1,588
Expenses
Production and mineral taxes									-				-				26				33
Transportation and processing									(15	)			(2	)			300				400
Operating									5				8				209				178
Purchased product									-				-				79				142
									(264	)			30				216				835
Depreciation, depletion and amortization									25				31				394				400
Impairments									-				-				2,081				-
								$	(289)			$	(1	)			(2,259	)			435
Accretion of asset retirement obligation																	11				13
Administrative																	84				98
Interest																	278				122
Foreign exchange (gain) loss, net																	(86	)			(172	)
(Gain) loss on divestitures																	(2	)			(204	)
Other																	4				8
																	289				(135	)
Net Earnings (Loss) Before Income Tax																	(2,548	)			570
Income tax expense (recovery)																	(938	)			289
Net Earnings (Loss)																	(1,610	)			281
Net earnings attributable to noncontrolling interest																	-				(10	)
Net Earnings (Loss) Attributable to Common Shareholders																$	(1,610	)		$	271
Intersegment Information
		Market Optimization
		Marketing Sales						Upstream Eliminations								Total
		2015		2014				2015				2014				2015				2014
Revenues, Net of Royalties		$         1,117		$	1,781			$	(1,029	)		$	(1,621	)		$	88			$	160
Expenses
Transportation and processing		89			123				(89	)			(123	)			-				-
Operating		8			19				-				(6	)			8				13
Purchased product		1,019			1,633				(940	)			(1,491	)			79				142
Operating Cash Flow		$                1		$	6			$	-			$	(1	)		$	1			$	5

 

		Notes to Condensed Consolidated Financial Statements Prepared in accordance with U.S. GAAP in US$

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Q2 Report  |  For the period ended June 30, 2015

 

Notes to Condensed Consolidated Financial Statements  (unaudited)

(All amounts in $ millions unless otherwise specified)

 

3.  Segmented Information (continued)

 

Results of Operations (For the six months ended June 30)

Segment and Geographic Information

 

		Canadian Operations						USA Operations								Market Optimization
		2015		2014				2015				2014				2015				2014
Revenues, Net of Royalties		$        1,019		$	1,947			$	1,217			$	1,351			$	227			$	404
Expenses
Production and mineral taxes		-			9				45				71				-				-
Transportation and processing		348			440				299				340				-				-
Operating		87			170				276				153				24				26
Purchased product		-			-				-				-				200				370
		584			1,328				597				787				3				8
Depreciation, depletion and amortization		173			337				637				415				-				4
Impairments		-			-				3,997				-				-				-
		$           411		$	991			$	(4,037	)		$	372			$	3			$	4
								Corporate & Other								Consolidated
								2015				2014				2015				2014
Revenues, Net of Royalties								$	(384	)		$	(222	)		$	2,079			$	3,480
Expenses
Production and mineral taxes									-				-				45				80
Transportation and processing									(7	)			(1	)			640				779
Operating									11				18				398				367
Purchased product									-				-				200				370
									(388	)			(239	)			796				1,884
Depreciation, depletion and amortization									50				62				860				818
Impairments									-				-				3,997				-
								$	(438	)		$	(301	)			(4,061	)			1,066
Accretion of asset retirement obligation																	23				26
Administrative																	156				200
Interest																	403				269
Foreign exchange (gain) loss, net																	570				52
(Gain) loss on divestitures																	(16	)			(203	)
Other																	5				8
																	1,141				352
Net Earnings (Loss) Before Income Tax																	(5,202	)			714
Income tax expense (recovery)																	(1,885	)			317
Net Earnings (Loss)																	(3,317	)			397
Net earnings attributable to noncontrolling interest																	-				(10	)
Net Earnings (Loss) Attributable to Common Shareholders																$	(3,317	)		$	387
Intersegment Information
		Market Optimization
		Marketing Sales						Upstream Eliminations								Total
		2015		2014				2015				2014				2015				2014
Revenues, Net of Royalties		$        2,282		$	4,008			$	(2,055	)		$	(3,604	)		$	227			$	404
Expenses
Transportation and processing		184			250				(184	)			(250	)			-				-
Operating		24			44				-				(18	)			24				26
Purchased product		2,071			3,703				(1,871	)			(3,333	)			200				370
Operating Cash Flow		$               3		$	11			$	-			$	(3	)		$	3			$	8

 

Notes to Condensed Consolidated Financial Statements Prepared in accordance with U.S. GAAP in US$

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Q2 Report  |  For the period ended June 30, 2015

 

Notes to Condensed Consolidated Financial Statements  (unaudited)

(All amounts in $ millions unless otherwise specified)

 

3.  Segmented Information (continued)

 

Capital Expenditures

 

										Three Months Ended June 30,								Six Months Ended June 30,
										2015				2014				2015				2014
Canadian Operations										$	114			$	350			$	265			$	631
USA Operations											628				206				1,211				432
Market Optimization											-				1				-				2
Corporate & Other											1				3				3				6
										$	743			$	560			$	1,479			$	1,071
Goodwill, Property, Plant and Equipment and Total Assets by Segment
		Goodwill								Property, Plant and Equipment								Total Assets
		As at								As at								As at
		June 30, 2015				December 31, 2014				June 30, 2015				December 31, 2014				June 30, 2015				December 31, 2014
Canadian Operations		$	733			$	788			$	1,320			$	2,338			$	2,413			$	3,632
USA Operations			2,129				2,129				10,311				13,817				12,749				16,800
Market Optimization			-				-				1				1				35				181
Corporate & Other			-				-				1,697				1,859				3,846				4,008
		$	2,862			$	2,917			$	13,329			$	18,015			$	19,043			$	24,621

 

4.  Business Combinations

Eagle Ford Acquisition

On June 20, 2014, Encana completed the acquisition of properties located in the Eagle Ford shale formation for approximately $2.9 billion, after closing adjustments. The acquisition included an interest in certain producing properties and undeveloped lands in the Karnes, Wilson and Atascosa counties of south Texas. Encana funded the acquisition with cash on hand. Transaction costs of approximately $9 million were included in other expenses.

Athlon Energy Inc. Acquisition

On November 13, 2014, Encana completed the acquisition of all of the issued and outstanding shares of common stock of Athlon Energy Inc. (“Athlon”) for $5.93 billion, or $58.50 per share. In addition, Encana assumed Athlon’s $1.15 billion senior notes and repaid and terminated Athlon’s credit facility with indebtedness outstanding of $335 million. Encana funded the acquisition of Athlon with cash on hand. Transaction costs of approximately $31 million were included in other expenses. Following completion of the acquisition, Athlon’s $1.15 billion senior notes were redeemed in accordance with the provisions of the governing indentures. Athlon’s operations focused on the acquisition and development of oil and gas properties located in the Permian Basin in Texas.

 

		Notes to Condensed Consolidated Financial Statements Prepared in accordance with U.S. GAAP in US$

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Q2 Report  |  For the period ended June 30, 2015

 

Notes to Condensed Consolidated Financial Statements  (unaudited)

(All amounts in $ millions unless otherwise specified)

 

4.  Business Combinations (continued)

 

Purchase Price Allocations

The transactions were accounted for under the acquisition method, which requires that the assets acquired and liabilities assumed be recognized at their fair values as of the acquisition date. The purchase price allocations, representing consideration paid and the fair values of the assets acquired and liabilities assumed as of the acquisition date, are shown in the table below.

 

Purchase Price Allocation		Eagle Ford (1)				Athlon (2, 3)
Assets Acquired:
Cash		$	-			$	2
Accounts receivable and other current assets			4				133
Risk management			-				80
Proved properties			2,873				2,124
Unproved properties			78				5,338
Other property, plant and equipment			-				2
Other assets			-				2
Goodwill			-				1,724
Liabilities Assumed:
Accounts payable and accrued liabilities			-				(195	)
Long-term debt, including revolving credit facility			-				(1,497	)
Asset retirement obligation			(32	)			(25	)
Deferred income taxes			-				(1,724	)
Total Purchase Price		$	2,923			$	5,964

 

(1)	The purchase price allocation for Eagle Ford is finalized.

(2)	The purchase price allocation for Athlon is preliminary. There were no changes during the first or second quarters of 2015.

(3)

The purchase price includes cash consideration paid for issued and outstanding shares of common stock of Athlon of $58.50 per share totaling $5.93 billion, as well as payments to terminate certain employment agreements with Athlon’s management and payments for certain other existing obligations of Athlon.

The Company used the income approach valuation technique for the fair value of assets acquired and liabilities assumed. The carrying amounts of cash, accounts receivable and other current assets, and accounts payable and accrued liabilities approximate their fair values due to the short-term maturity of the instruments. The fair values of the risk management assets and long-term debt, including the revolving credit facility, are categorized within Level 2 of the fair value hierarchy and were determined using quoted prices and rates from an available pricing source. The fair values of the proved and unproved properties, other property, plant and equipment, other assets, goodwill, and asset retirement obligation are categorized within Level 3 and were determined using relevant market assumptions, including discount rates, future commodity prices and costs, timing of development activities, projections of oil and gas reserves, and estimates to abandon and reclaim producing wells.

Goodwill arose from the Athlon acquisition primarily from the requirement to recognize deferred taxes on the difference between the fair value of the assets acquired and liabilities assumed and the respective carry-over tax basis. Goodwill is not amortized and is not deductible for tax purposes.

 

Notes to Condensed Consolidated Financial Statements Prepared in accordance with U.S. GAAP in US$

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Q2 Report  |  For the period ended June 30, 2015

 

Notes to Condensed Consolidated Financial Statements  (unaudited)

(All amounts in $ millions unless otherwise specified)

 

4.  Business Combinations (continued)

 

Unaudited Pro Forma Financial Information

The following unaudited pro forma financial information combines the historical financial results of Encana with Eagle Ford and Athlon, and has been prepared assuming the acquisitions occurred on January 1, 2014. The pro forma information is not intended to reflect the actual results of operations that would have occurred if the business combinations had been completed at the date indicated. In addition, the pro forma information does not project Encana’s results of operations for any future period. The Company’s consolidated results for the six months ended June 30, 2015 include the results from Eagle Ford and Athlon.

 

Six Months Ended June 30, 2014 ($ millions, except per share amounts)										Eagle Ford				Athlon
Revenues, Net of Royalties										$	4,221			$	3,678
Net Earnings										$	650			$	377
Net Earnings per Common Share
Basic & Diluted										$	0.88			$	0.51
5.  Acquisitions and Divestitures
		Three Months Ended June 30,								Six Months Ended June 30,
		2015				2014				2015				2014
Acquisitions
Canadian Operations		$	1			$	-			$	1			$	2
USA Operations			2				2,923				3				2,944
Corporate & Other			-				-				34				-
Total Acquisitions			3				2,923				38				2,946
Divestitures
Canadian Operations			(50	)			(89	)			(879	)			(121	)
USA Operations			(87	)			(2,156	)			(84	)			(2,170	)
Corporate & Other			(6	)			(26	)			(53	)			(27	)
Total Divestitures			(143	)			(2,271	)			(1,016	)			(2,318	)
Net Acquisitions & (Divestitures)		$	(140	)		$	652			$	(978	)		$	628

Acquisitions

During the three and six months ended June 30, 2014, acquisitions primarily included the purchase of certain properties in the Eagle Ford shale formation in south Texas as described in Note 4.

Divestitures

For the three and six months ended June 30, 2015, divestitures in the Canadian Operations were $50 million and $879 million, respectively (2014 - $89 million and $121 million, respectively). Divestitures primarily included the sale of certain assets included in Wheatland located in central and southern Alberta for proceeds of approximately C$558 million ($468 million), after closing adjustments, the sale of certain natural gas gathering and compression assets in the Montney area of northeastern British Columbia for proceeds of approximately C$454 million ($358 million), after closing adjustments and the sale of land and properties that do not complement Encana’s existing portfolio of assets.

For the three and six months ended June 30, 2015, divestitures in the USA Operations were $87 million and $84 million, respectively, which primarily included the sale of land and properties that do not complement Encana’s existing portfolio of assets. During the three and six months ended June 30, 2014, divestitures in the USA Operations were $2,156 million and $2,170 million, respectively, which primarily included the sale of the Jonah properties for proceeds of approximately $1,639 million and the sale of certain properties in East Texas for proceeds of approximately $427 million, after closing adjustments.

The proved reserves associated with the Jonah divestiture exceeded 25 percent of Encana’s proved reserves in the U.S. cost centre. The carrying amount of the assets was deducted from the full cost pool and the remainder of the proceeds was recognized as a gain on sale of approximately $212 million, before tax. For divestitures that result in a gain or loss on sale and constitute a business, goodwill is assigned to the transaction. Accordingly, goodwill of $68 million was allocated to the Jonah divestiture.

Amounts received from the divestiture transactions have been deducted from the respective Canadian and U.S. full cost pools, except for the Jonah divestiture as noted above.

For the six months ended June 30, 2015, Corporate and Other acquisitions and divestitures primarily includes the purchase and subsequent sale of the Encana Place office building located in Calgary, which resulted in a gain on divestiture of approximately $12 million.

 

		Notes to Condensed Consolidated Financial Statements Prepared in accordance with U.S. GAAP in US$

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Q2 Report  |  For the period ended June 30, 2015

 

Notes to Condensed Consolidated Financial Statements  (unaudited)

(All amounts in $ millions unless otherwise specified)

 

6.  Interest

 

		Three Months Ended June 30,								Six Months Ended June 30,
		2015				2014				2015				2014
Interest Expense on:
Debt		$	248			$	96			$	343			$	208
The Bow office building			18				19				34				38
Capital leases			6				10				15				19
Other			6				(3	)			11				4
		$	278			$	122			$	403			$	269
Interest Expense on Debt for the three and six months ended June 30, 2015 includes a one-time interest payment of approximately $165 million resulting from the early redemption of the Company’s $700 million 5.90 percent notes due December 1, 2017 and C$750 million 5.80 percent medium-term notes due January 18, 2018 as discussed in Note 10.
7.  Foreign Exchange (Gain) Loss, Net
		Three Months Ended June 30,								Six Months Ended June 30,
		2015				2014				2015				2014
Unrealized Foreign Exchange (Gain) Loss on:
Translation of U.S. dollar debt issued from Canada		$	(123	)		$	(184	)		$	341			$	20
Translation of U.S. dollar risk management contracts issued from Canada			6				6				(29	)			(1	)
Translation of intercompany notes			(128	)			-				2				-
			(245	)			(178	)			314				19
Foreign Exchange on Settlements			137				1				235				27
Other Monetary Revaluations			22				5				21				6
		$	(86	)		$	(172	)		$	570			$	52
Foreign Exchange on Settlements includes foreign exchange on intercompany transactions and foreign exchange on settlement of long-term debt previously reported in Other Monetary Revaluations.
8.  Income Taxes
		Three Months Ended June 30,								Six Months Ended June 30,
		2015				2014				2015				2014
Current Tax
Canada		$	(38	)		$	(27	)		$	(25	)		$	(20	)
United States			2				4				3				7
Other countries			1				4				3				10
Total Current Tax Expense (Recovery)			(35	)			(19	)			(19	)			(3	)
Deferred Tax
Canada			(155	)			224				(478	)			228
United States			(879	)			69				(1,639	)			71
Other countries			131				15				251				21
Total Deferred Tax Expense (Recovery)			(903	)			308				(1,866	)			320
		$	(938	)		$	289			$	(1,885	)		$	317

Encana’s interim income tax expense is determined using an estimated annual effective income tax rate applied to year-to-date net earnings before income tax plus the effect of legislative changes, including the 2015 Alberta general corporate income tax rate increase, and amounts in respect of prior periods. The estimated annual effective income tax rate is impacted by the expected annual earnings, statutory rate and other foreign differences, non-taxable capital gains and losses, tax differences on divestitures and transactions, and partnership tax allocations in excess of funding.

 

Notes to Condensed Consolidated Financial Statements Prepared in accordance with U.S. GAAP in US$

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Q2 Report  |  For the period ended June 30, 2015

 

Notes to Condensed Consolidated Financial Statements  (unaudited)

(All amounts in $ millions unless otherwise specified)

 

9.  Property, Plant and Equipment, Net

 

		As at June 30, 2015												As at December 31, 2014
		Cost				Accumulated DD&A (1)				Net				Cost				Accumulated DD&A (1)				Net
Canadian Operations
Proved properties		$	16,361			$	(15,581)			$	780			$	18,271			$	(16,566)			$	1,705
Unproved properties			420				-				420				478				-				478
Other			120				-				120				155				-				155
			16,901				(15,581)				1,320				18,904				(16,566)				2,338
USA Operations
Proved properties			25,662				(20,891)				4,771				24,279				(16,260)				8,019
Unproved properties			5,435				-				5,435				5,655				-				5,655
Other			105				-				105				143				-				143
			31,202				(20,891)				10,311				30,077				(16,260)				13,817
Market Optimization			8				(7)				1				8				(7)				1
Corporate & Other			2,306				(609)				1,697				2,470				(611)				1,859
		$	50,417			$	(37,088)			$	13,329			$	51,459			$	(33,444)			$	18,015

 

(1)	Depreciation, depletion and amortization.

Canadian Operations and USA Operations property, plant and equipment include internal costs directly related to exploration, development and construction activities of $128 million which have been capitalized during the six months ended June 30, 2015 (2014 - $195 million). Included in Corporate and Other are $61 million ($65 million as at December 31, 2014) of international property costs, which have been fully impaired.

For the three and six months ended June 30, 2015, the Company recognized before-tax ceiling test impairments of $2,081 million and $3,997 million, respectively (2014 - nil) in the U.S. cost centre, which are included within accumulated DD&A in the table above. The impairments resulted primarily from the decline in the 12-month average trailing commodity prices which reduced proved reserves volumes and values. There were no ceiling test impairments in the Canadian cost centre for the three and six months ended June 30, 2015 (2014 - nil).

The 12-month average trailing prices used in the ceiling test calculations were based on the benchmark prices below. The benchmark prices were adjusted for basis differentials to determine local reference prices, transportation costs and tariffs, heat content and quality.

 

		Natural Gas								Oil & NGLs
		Henry Hub             ($/MMBtu)				AECO (C$/MMBtu)				WTI                 ($/bbl)				Edmonton Light Sweet (C$/bbl)
12-Month Average Trailing Reserves Pricing
June 30, 2015			3.38				3.32				71.68				75.58
December 31, 2014			4.34				4.63				94.99				96.40
June 30, 2014			4.10				4.11				100.27				98.20

Capital Lease Arrangements

The Company has several lease arrangements that are accounted for as capital leases, including an office building, equipment and an offshore production platform.

In December 2013, Encana commenced commercial operations at its Deep Panuke facility located offshore Nova Scotia at which time the Company recorded a capital lease asset and a corresponding capital lease obligation related to the Production Field Centre (“PFC”). Variable interests related to the PFC are described in Note 16.

As at June 30, 2015, the total carrying value of assets under capital lease was $443 million ($547 million as at December 31, 2014). Liabilities for the capital lease arrangements are included in other liabilities and provisions in the Condensed Consolidated Balance Sheet and are disclosed in Note 11.

 

		Notes to Condensed Consolidated Financial Statements Prepared in accordance with U.S. GAAP in US$

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Q2 Report  |  For the period ended June 30, 2015

 

Notes to Condensed Consolidated Financial Statements  (unaudited)

(All amounts in $ millions unless otherwise specified)

 

9.  Property, Plant and Equipment, Net (continued)

 

Other Arrangement

As at June 30, 2015, Corporate and Other property, plant and equipment and total assets include a carrying value of $1,319 million ($1,431 million as at December 31, 2014) related to The Bow office building, which is under a 25-year lease agreement. The Bow asset is being depreciated over the 60-year estimated life of the building. At the conclusion of the 25-year term, the remaining asset and corresponding liability are expected to be derecognized as disclosed in Note 11.

 

10.  Long-Term Debt

 

		C$ Principal Amount				As at           June 30, 2015				As at       December 31, 2014
Canadian Dollar Denominated Debt
5.80% due January 18, 2018		$	-			$	-			$	647
U.S. Dollar Denominated Debt
Revolving credit and term loan borrowings							1,397				1,277
U.S. Unsecured Notes
5.90% due December 1, 2017							-				700
6.50% due May 15, 2019							500				500
3.90% due November 15, 2021							600				600
8.125% due September 15, 2030							300				300
7.20% due November 1, 2031							350				350
7.375% due November 1, 2031							500				500
6.50% due August 15, 2034							750				750
6.625% due August 15, 2037							500				500
6.50% due February 1, 2038							800				800
5.15% due November 15, 2041							400				400
							6,097				6,677
Total Principal							6,097				7,324
Increase in Value of Debt Acquired							31				34
Debt Discounts							(16	)			(18	)
Current Portion of Long-Term Debt							-				-
						$	6,112			$	7,340

Long-term debt is accounted for at amortized cost using the effective interest method of amortization. As at June 30, 2015, total long-term debt had a carrying value of $6,112 million and a fair value of $6,448 million (as at December 31, 2014 - carrying value of $7,340 million and a fair value of $7,788 million). The estimated fair value of long-term borrowings is categorized within Level 2 of the fair value hierarchy and has been determined based on market information, or by discounting future payments of interest and principal at interest rates expected to be available to the Company at period end.

On March 5, 2015, Encana provided notice to note holders that it would redeem the Company’s $700 million 5.90 percent notes due December 1, 2017 and C$750 million 5.80 percent medium-term notes due January 18, 2018. On April 6, 2015, the Company used net proceeds from the common shares issued, as disclosed in Note 13, and cash on hand to complete the note redemptions. In conjunction with the early note redemptions, the Company incurred a one-time interest payment of approximately $165 million as discussed in Note 6.

On February 28, 2014, Encana announced a cash tender offer and consent solicitation for any and all of the Company’s outstanding $1,000 million 5.80 percent notes with a maturity date of May 1, 2014. The Company paid $1,004.59 for each $1,000 principal amount of the notes plus accrued and unpaid interest up to, but not including, the settlement date and a consent payment equal to $2.50 per $1,000 principal amount of the notes.

On March 28, 2014, the tender offer and consent solicitation expired and on March 31, 2014, Encana paid the consenting note holders an aggregate of approximately $792 million in cash reflecting a $768 million principal debt repayment, $2 million for the consent payment and $22 million of accrued and unpaid interest.

On April 28, 2014, pursuant to the Notice of Redemption issued on March 28, 2014, the Company redeemed the remaining principal amount of the 5.80 percent notes not tendered in the tender offer. Encana paid approximately $239 million in cash reflecting a $232 million principal debt repayment and $7 million of accrued and unpaid interest.

 

Notes to Condensed Consolidated Financial Statements Prepared in accordance with U.S. GAAP in US$

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Q2 Report  |  For the period ended June 30, 2015

 

Notes to Condensed Consolidated Financial Statements  (unaudited)

(All amounts in $ millions unless otherwise specified)

 

11.  Other Liabilities and Provisions

 

		As at         June 30, 2015				As at   December 31, 2014
The Bow Office Building (See Note 9)		$	1,378			$	1,486
Capital Lease Obligations (See Note 9)			416				473
Unrecognized Tax Benefits			245				279
Pensions and Other Post-Employment Benefits			153				144
Long-Term Incentives (See Note 18)			32				70
Other			44				32
		$	2,268			$	2,484

The Bow Office Building

As described in Note 9, Encana has recognized the accumulated costs for The Bow office building, which is under a 25-year lease agreement. At the conclusion of the 25-year term, the remaining asset and corresponding liability are expected to be derecognized. Encana has also subleased part of The Bow office space to a subsidiary of Cenovus Energy Inc. (“Cenovus”). The total undiscounted future payments related to the lease agreement and the total undiscounted future amounts expected to be recovered from the Cenovus sublease are outlined below.

 

(undiscounted)		2015				2016				2017				2018				2019				Thereafter				Total
Expected Future Lease Payments		$	37			$	75			$	76			$	76			$	77			$	1,538			$	1,879
Sublease Recoveries		$	(18	)		$	(37	)		$	(37	)		$	(38	)		$	(38	)		$	(755	)		$	(923	)
Capital Lease Obligations   As described in Note 9, the Company has several lease arrangements that are accounted for as capital leases, including an office building, equipment and an offshore production platform. Variable interests related to the PFC are described in Note 16.   The total expected future lease payments related to the Company’s capital lease obligations are outlined below.
		2015				2016				2017				2018				2019				Thereafter				Total
Expected Future Lease Payments		$	49			$	98			$	99			$	99			$	99			$	232			$	676
Less Amounts Representing
Interest			21				40				36				32				28				47				204
Present Value of Expected
Future Lease Payments		$	28			$	58			$	63			$	67			$	71			$	185			$	472

 

		Notes to Condensed Consolidated Financial Statements Prepared in accordance with U.S. GAAP in US$

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Q2 Report  |  For the period ended June 30, 2015

 

Notes to Condensed Consolidated Financial Statements  (unaudited)

(All amounts in $ millions unless otherwise specified)

 

12.  Asset Retirement Obligation

 

		As at       June 30, 2015				As at   December 31, 2014
Asset Retirement Obligation, Beginning of Year		$	913			$	966
Liabilities Incurred and Acquired (See Note 4)			12				85
Liabilities Settled and Divested			(113	)			(188	)
Change in Estimated Future Cash Outflows			-				35
Accretion Expense			23				52
Foreign Currency Translation			(28	)			(37	)
Asset Retirement Obligation, End of Period		$	807			$	913
Current Portion		$	42			$	43
Long-Term Portion			765				870
		$	807			$	913

 

13.  Share Capital

Authorized

The Company is authorized to issue an unlimited number of no par value common shares and Class A preferred shares limited to a number equal to not more than 20 percent of the issued and outstanding number of common shares.

Issued and Outstanding

 

		As at June 30, 2015								As at December 31, 2014
		Number         (millions)				Amount				Number         (millions)				Amount
Common Shares Outstanding, Beginning of Year			741.2			$	2,450				740.9			$	2,445
Common Shares Issued			98.4				1,098				-				-
Common Shares Issued Under Dividend Reinvestment Plan			2.9				32				0.3				5
Common Shares Outstanding, End of Period			842.5			$	3,580				741.2			$	2,450

On March 5, 2015, Encana filed a prospectus supplement (the “Share Offering”) to the Company’s base shelf prospectus for the issuance of 85,616,500 common shares and granted an over-allotment option for up to an additional 12,842,475 common shares at a price of C$14.60 per common share, pursuant to an underwriting agreement. The aggregate gross proceeds from the Share Offering were approximately C$1.44 billion ($1.13 billion). After deducting underwriter’s fees and costs of the Share Offering, the net proceeds received were approximately C$1.39 billion ($1.09 billion).

During the six months ended June 30, 2015, Encana issued 2,872,237 common shares totaling $32 million under the Company’s dividend reinvestment plan (“DRIP”). During the twelve months ended December 31, 2014, Encana issued 240,839 common shares totaling $5 million under the DRIP.

Dividends

During the three months ended June 30, 2015, Encana paid dividends of $0.07 per common share totaling $55 million (2014 - $0.07 per common share totaling $52 million). During the six months ended June 30, 2015, Encana paid dividends of $0.14 per common share totaling $107 million (2014 - $0.14 per common share totaling $104 million). Common shares issued as part of the Share Offering as described above were not eligible to receive the dividend paid on March 31, 2015.

For the three and six months ended June 30, 2015, the dividends paid included $18 million and $32 million, respectively, in common shares issued in lieu of cash dividends under the DRIP (for the three and six months ended June 30, 2014 - $2 million and $3 million, respectively).

 

Notes to Condensed Consolidated Financial Statements Prepared in accordance with U.S. GAAP in US$

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Q2 Report  |  For the period ended June 30, 2015

 

Notes to Condensed Consolidated Financial Statements  (unaudited)

(All amounts in $ millions unless otherwise specified)

 

13.  Share Capital (continued)

 

Earnings Per Common Share

The following table presents the computation of net earnings per common share:

 

		Three Months Ended June 30,								Six Months Ended June 30,
(millions, except per share amounts)		2015				2014				2015				2014
Net Earnings (Loss) Attributable to Common Shareholders		$	(1,610	)		$	271			$	(3,317	)		$	387
Number of Common Shares:
Weighted average common shares outstanding - Basic			841.2				741.0				799.5				741.0
Effect of dilutive securities			-				-				-				-
Weighted average common shares outstanding - Diluted			841.2				741.0				799.5				741.0
Net Earnings (Loss) per Common Share
Basic		$	(1.91	)		$	0.37			$	(4.15	)		$	0.52
Diluted		$	(1.91	)		$	0.37			$	(4.15	)		$	0.52

Encana Stock Option Plan

Encana has share-based compensation plans that allow employees to purchase common shares of the Company. Option exercise prices are not less than the market value of the common shares on the date the options are granted. All options outstanding as at June 30, 2015 have associated Tandem Stock Appreciation Rights (“TSARs”) attached. In lieu of exercising the option, the associated TSARs give the option holder the right to receive a cash payment equal to the excess of the market price of Encana’s common shares at the time of the exercise over the original grant price.

In addition, certain stock options granted are performance-based whereby vesting is also subject to Encana attaining prescribed performance relative to predetermined key measures. Historically, most holders of options with TSARs have elected to exercise their stock options as a Stock Appreciation Right (“SAR”) in exchange for a cash payment. As a result, Encana does not consider outstanding TSARs to be potentially dilutive securities.

Encana Restricted Share Units (“RSUs”)

Encana has a share-based compensation plan whereby eligible employees are granted RSUs. An RSU is a conditional grant to receive an Encana common share, or the cash equivalent, as determined by Encana, upon vesting of the RSUs and in accordance with the terms of the RSU Plan and Grant Agreement. The Company intends to settle vested RSUs in cash on the vesting date. As a result, Encana does not consider RSUs to be potentially dilutive securities.

 

		Notes to Condensed Consolidated Financial Statements Prepared in accordance with U.S. GAAP in US$

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Q2 Report  |  For the period ended June 30, 2015

 

Notes to Condensed Consolidated Financial Statements  (unaudited)

(All amounts in $ millions unless otherwise specified)

 

14.  Accumulated Other Comprehensive Income

 

		Three Months Ended June 30,								Six Months Ended June 30,
		2015				2014				2015				2014
Foreign Currency Translation Adjustment
Balance, Beginning of Period		$	1,193			$	717			$	715			$	693
Current Period Change in Foreign Currency Translation Adjustment			(53	)			(2	)			425				22
Balance, End of Period		$	1,140			$	715			$	1,140			$	715
Pension and Other Post-Employment Benefit Plans
Balance, Beginning of Period		$	(25	)		$	(9	)		$	(26	)		$	(9	)
Reclassification of Net Actuarial (Gains) and Losses to Net Earnings (See Note 19)			-				-				1				-
Income Taxes			-				-				-				-
Balance, End of Period		$	(25	)		$	(9	)		$	(25	)		$	(9	)
Total Accumulated Other Comprehensive Income		$	1,115			$	706			$	1,115			$	706

 

15.  Noncontrolling Interest

Initial Public Offering of Common Shares of PrairieSky

On May 29, 2014, Encana completed an initial public offering (“IPO”) of 52.0 million common shares of PrairieSky at a price of C$28.00 per common share for gross proceeds of approximately C$1.46 billion. On June 3, 2014, the over-allotment option granted to the underwriters to purchase up to an additional 7.8 million common shares was exercised in full for gross proceeds of approximately C$218.4 million. Encana received aggregate gross proceeds from the IPO of approximately C$1.67 billion ($1.54 billion). As at June 30, 2014, Encana owned 70.2 million common shares of PrairieSky, representing a 54 percent ownership interest. Accordingly, Encana consolidated 100 percent of the financial position and results of operations of PrairieSky and recognized a noncontrolling interest for the third party ownership.

The noncontrolling interest in the former consolidated subsidiary, PrairieSky, was reflected as a separate component in the Condensed Consolidated Statement of Changes in Shareholders’ Equity for the six months ended June 30, 2014. Encana recorded $117 million of the proceeds from the IPO as a noncontrolling interest and the remainder of the proceeds of $1,427 million, less transaction costs of $73 million, was recognized as paid in surplus as at June 30, 2014. For the three and six months ended June 30, 2014, net earnings and comprehensive income of $10 million were attributable to the noncontrolling interest as presented in the Condensed Consolidated Statement of Earnings and Condensed Consolidated Statement of Comprehensive Income, respectively.

Distributions to Noncontrolling Interest Owners

On June 18, 2014, PrairieSky declared a dividend of C$0.1058 per common share payable on July 15, 2014 to PrairieSky common shareholders totaling $13 million, of which $6 million was attributable to the noncontrolling interest as presented in the Condensed Consolidated Statement of Changes in Shareholders’ Equity.

Secondary Public Offering of Common Shares of PrairieSky

On September 26, 2014, Encana completed the secondary offering of 70.2 million common shares of PrairieSky at a price of C$36.50 per common share, for aggregate gross proceeds to Encana of approximately C$2.6 billion. Following the completion of the secondary offering, Encana no longer held an interest in PrairieSky.

 

Notes to Condensed Consolidated Financial Statements Prepared in accordance with U.S. GAAP in US$

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Q2 Report  |  For the period ended June 30, 2015

 

Notes to Condensed Consolidated Financial Statements  (unaudited)

(All amounts in $ millions unless otherwise specified)

 

16.  Variable Interest Entities

Production Field Centre

In 2008, Encana entered into a contract for the design, construction and operation of the PFC at its Deep Panuke facility. Upon commencement of operations in December 2013, Encana recognized the PFC as a capital lease asset as described in Note 9. Under the lease contract, Encana has a purchase option and the option to extend the lease for 12 one-year terms at fixed prices after the initial lease term expires in 2021.

As a result of the purchase option and fixed price renewal options, Encana has determined it holds variable interests and that the related leasing entity qualifies as a variable interest entity (“VIE”). Encana is not the primary beneficiary of the VIE as the Company does not have the power to direct the activities that most significantly impact the VIE’s economic performance. Encana is not required to provide any financial support or guarantees to the leasing entity or its affiliates, other than the contractual payments under the lease and operating agreements. Encana’s maximum exposure to loss is the expected lease payments over the initial contract term. As at June 30, 2015, Encana’s capital lease obligation of $404 million ($462 million as at December 31, 2014) related to the PFC.

Veresen Midstream Limited Partnership

On March 31, 2015, Encana, along with the Cutbank Ridge Partnership (“CRP”), entered into natural gas gathering and compression agreements with Veresen Midstream Limited Partnership (“VMLP”), under an initial term of 30 years with two potential five-year renewal terms. As part of the agreement, VMLP agreed to undertake expansion of future midstream services in support of Encana and the CRP’s development of the Montney play. In addition, VMLP will also provide to Encana and the CRP natural gas gathering and processing under existing agreements that were contributed to VMLP by its partner Veresen Inc., with remaining terms of 17 years and up to a potential maximum of 10 one-year renewal terms.

Encana has determined that VMLP is a VIE and that Encana holds variable interests in VMLP. Encana is not the primary beneficiary as the Company does not have the power to direct the activities that most significantly impact VMLP’s economic performance. These key activities relate to the construction, operation, maintenance and marketing of the assets owned by VMLP. The variable interests arise from certain terms under the long-term service agreements which include: i) a take or pay for volumes committed to certain gathering and processing assets; ii) an operating fee of which a portion can be converted into a take or pay once VMLP assumes operatorship of certain compression assets; and iii) a potential payout of minimum costs associated with certain gathering and compression assets. The potential payout of minimum costs will be assessed in the eighth year of the assets’ service period and is based on whether there is an overall shortfall of total system cash flows from natural gas gathered and compressed under certain service agreements. The potential payout amount can be reduced in the event VMLP markets unutilized capacity to third party users. Encana is not required to provide any financial support or guarantees to VMLP.

The total maximum exposure to loss as a result of Encana’s involvement with VMLP is estimated to be $1,215 million as at June 30, 2015 and is based on the future take or pay for volumes committed to certain gathering and processing assets and the potential payout of minimum costs associated with certain gathering and compression assets. The total maximum exposure to loss associated with the potential payout requirement is highly uncertain as the payout amount is contingent on future production estimates, pace of development and capacity contracted to third parties. As at June 30, 2015, there were no accounts payable and accrued liabilities outstanding related to the take or pay commitment. The take or pay for volumes committed to certain gathering and processing agreements are included in Note 22.

 

		Notes to Condensed Consolidated Financial Statements Prepared in accordance with U.S. GAAP in US$

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Q2 Report  |  For the period ended June 30, 2015

 

Notes to Condensed Consolidated Financial Statements  (unaudited)

(All amounts in $ millions unless otherwise specified)

 

17.    Restructuring Charges

In November 2013, Encana announced its plans to align the organizational structure in support of the Company’s strategy. Since the announcement, the Company has incurred restructuring charges primarily related to severance costs totaling $125 million, of which $2 million remains accrued as at June 30, 2015. Total restructuring charges are expected to be approximately $135 million before tax. For the six months ended June 30, 2015, $1 million in restructuring charges were incurred (2014 - $22 million). The remaining restructuring charges of approximately $10 million are anticipated to be incurred during the remainder of 2015. Restructuring charges are included in administrative expense in the Condensed Consolidated Statement of Earnings.

During the second quarter of 2015, Encana revised its plans to align the organizational structure in continued support of the Company’s strategy. Additional transition and severance costs are expected to total approximately $58 million before tax. For the six months ended June 30, 2015, costs of $30 million were incurred, of which $13 million remains accrued. The remaining transition and severance costs of approximately $28 million are expected to be incurred during the remainder of 2015.

 

18.  Compensation Plans

Encana has a number of compensation arrangements under which the Company awards various types of long-term incentive grants to eligible employees. These primarily include TSARs, Performance TSARs, SARs, Performance SARs, Performance Share Units (“PSUs”), Deferred Share Units (“DSUs”) and RSUs. These compensation arrangements are share-based.

Encana accounts for TSARs, Performance TSARs, SARs, Performance SARs, PSUs and RSUs held by Encana employees as cash-settled share-based payment transactions and, accordingly, accrues compensation costs over the vesting period based on the fair value of the rights determined using the Black-Scholes-Merton and other fair value models.

As at June 30, 2015, the following weighted average assumptions were used to determine the fair value of the share units held by Encana employees:

 

		Encana US$ Share Units				Encana C$ Share Units
Risk Free Interest Rate			0.56%				0.56%
Dividend Yield			2.54%				2.51%
Expected Volatility Rate			30.71%				28.54%
Expected Term			1.7 yrs				1.8 yrs
Market Share Price			US$11.02				C$13.77

 

Notes to Condensed Consolidated Financial Statements Prepared in accordance with U.S. GAAP in US$

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Q2 Report  |  For the period ended June 30, 2015

 

Notes to Condensed Consolidated Financial Statements  (unaudited)

(All amounts in $ millions unless otherwise specified)

 

18.  Compensation Plans (continued)

 

The Company has recognized the following share-based compensation costs:

 

		Three Months Ended   June 30,								Six Months Ended   June 30,
		2015				2014				2015				2014
Compensation Costs of Transactions Classified as Cash-Settled		$		13		$	57			$		7		$	129
Compensation Costs of Transactions Classified as Equity-Settled (1)				-			1					-			(1	)
Total Share-Based Compensation Costs				13			58					7			128
Less: Total Share-Based Compensation Costs Capitalized				(5)			(20	)				(2)			(46	)
Total Share-Based Compensation Expense		$		8		$	38			$		5		$	82
Recognized on the Condensed Consolidated Statement of Earnings in:
Operating expense		$		3		$	16			$		1		$	36
Administrative expense				5			22					4			46
		$		8		$	38			$		5		$	82

 

(1)

RSUs may be settled in cash or equity as determined by Encana. The Company’s decision to cash settle RSUs was made subsequent to the original grant date.

As at June 30, 2015, the liability for share-based payment transactions totaled $95 million ($99 million as at December 31, 2014), of which $63 million ($29 million as at December 31, 2014) is recognized in accounts payable and accrued liabilities in the Condensed Consolidated Balance Sheet.

 

		As at         June 30, 2015				As at December 31, 2014
Liability for Cash-Settled Share-Based Payment Transactions:
Unvested		$	79			$	78
Vested			16				21
		$	95			$	99

The following units were granted primarily in conjunction with the Company’s March annual long-term incentive award. The TSARs and SARs were granted at the volume-weighted average trading price of Encana’s common shares for the five days prior to the grant date.

 

Six Months Ended June 30, 2015 (thousands of units)
TSARs			1,934
SARs			1,444
PSUs			2,319
DSUs			172
RSUs			6,557

 

		Notes to Condensed Consolidated Financial Statements Prepared in accordance with U.S. GAAP in US$

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Q2 Report  |  For the period ended June 30, 2015

 

Notes to Condensed Consolidated Financial Statements  (unaudited)

(All amounts in $ millions unless otherwise specified)

 

19.  Pension and Other Post-Employment Benefits

The Company has recognized total benefit plans expense which includes pension benefits and other post-employment benefits (“OPEB”) for the six months ended June 30 as follows:

 

		Pension Benefits								OPEB								Total
		2015				2014				2015				2014				2015				2014
Defined Benefit Plan Expense		$		1		$	-			$	7			$	6			$	8			$	6
Defined Contribution Plan Expense				15			17				-				-				15				17
Total Benefit Plans Expense		$		16		$	17			$	7			$	6			$	23			$	23
Of the total benefit plans expense, $18 million (2014 - $17 million) was included in operating expense and $5 million (2014 - $6 million) was included in administrative expense.   The defined periodic pension and OPEB expense for the six months ended June 30 are as follows:
		Pension Benefits								OPEB								Total
		2015				2014				2015				2014				2015				2014
Current Service Costs		$		2		$	2			$	5			$	4			$	7			$	6
Interest Cost				5			6				2				2				7				8
Expected Return On Plan Assets				(7)			(8	)			-				-				(7	)			(8	)
Amounts Reclassified From Accumulated Other Comprehensive Income:
Amortization of net actuarial (gains) and losses				1			-				-				-				1				-
Total Defined Benefit Plan Expense		$		1		$	-			$	7			$	6			$	8			$	6
The amounts recognized in other comprehensive income for the six months ended June 30 are as follows:
		Pension Benefits								OPEB								Total
		2015				2014				2015				2014				2015				2014
Total Amounts Recognized in Other Comprehensive (Income) Loss, Before Tax		$		(1)		$	-			$	-			$	-			$	(1	)		$	-
Total Amounts Recognized in Other Comprehensive (Income) Loss, After Tax		$		(1)		$	-			$	-			$	-			$	(1	)		$	-

 

Notes to Condensed Consolidated Financial Statements Prepared in accordance with U.S. GAAP in US$

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Q2 Report  |  For the period ended June 30, 2015

 

Notes to Condensed Consolidated Financial Statements  (unaudited)

(All amounts in $ millions unless otherwise specified)

 

20.  Fair Value Measurements

The fair values of cash and cash equivalents, accounts receivable and accrued revenues, and accounts payable and accrued liabilities approximate their carrying amounts due to the short-term maturity of those instruments. The fair value of cash in reserve approximates its carrying amount due to the nature of the instrument held.

Recurring fair value measurements are performed for risk management assets and liabilities and are discussed further in Note 21. These items are carried at fair value in the Condensed Consolidated Balance Sheet and are classified within the three levels of the fair value hierarchy in the tables below. There have been no transfers between the hierarchy levels during the period.

 

As at June 30, 2015		Level 1 Quoted       Prices in Active Markets				Level 2 Other Observable Inputs				Level 3 Significant Unobservable Inputs				Total Fair Value				Netting (1)				Carrying Amount
Risk Management
Risk Management Assets
Current		$	-			$	390			$	-			$	390			$	(60	)		$	330
Long-term			-				14				-				14				(3	)			11
Risk Management Liabilities
Current			-				82				4				86				(60	)			26
Long-term			-				12				6				18				(3	)			15
As at December 31, 2014		Level 1 Quoted       Prices in Active Markets				Level 2 Other Observable Inputs				Level 3 Significant Unobservable Inputs				Total Fair Value				Netting (1)				Carrying Amount
Risk Management
Risk Management Assets
Current		$	-			$	718			$	-			$	718			$	(11	)		$	707
Long-term			-				67				-				67				(2	)			65
Risk Management Liabilities
Current			6				14				11				31				(11	)			20
Long-term			-				2				7				9				(2	)			7

 

(1)

Netting to offset derivative assets and liabilities where the legal right and intention to offset exists, or where counterparty master netting arrangements contain provisions for net settlement.

 

		Notes to Condensed Consolidated Financial Statements Prepared in accordance with U.S. GAAP in US$

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Q2 Report  |  For the period ended June 30, 2015

 

Notes to Condensed Consolidated Financial Statements  (unaudited)

(All amounts in $ millions unless otherwise specified)

 

20.  Fair Value Measurements (continued)

 

The Company’s Level 1 and Level 2 risk management assets and liabilities consist of commodity fixed price contracts and basis swaps with terms to 2018. The fair values of these contracts are based on a market approach and are estimated using inputs which are either directly or indirectly observable at the reporting date, such as exchange and other published prices, broker quotes and observable trading activity.

Level 3 Fair Value Measurements

As at June 30, 2015, the Company’s Level 3 risk management assets and liabilities consist of power purchase contracts with terms to 2017. The fair values of the power purchase contracts are based on the income approach and are modelled internally using observable and unobservable inputs such as forward power prices in less active markets. The unobservable inputs are obtained from third parties whenever possible and reviewed by the Company for reasonableness.

Changes in amounts related to risk management assets and liabilities are recognized in revenues and transportation and processing expense according to their purpose.

A summary of changes in Level 3 fair value measurements for the six months ended June 30 is presented below:

 

		Risk Management
		2015				2014
Balance, Beginning of Year		$	(18	)		$	(7	)
Total Gains (Losses)			-				(3	)
Purchases and Settlements:
Purchases			-				-
Settlements			8				4
Transfers in and out of Level 3			-				-
Balance, End of Period		$	(10	)		$	(6	)
Change in unrealized gains (losses) related to
assets and liabilities held at end of period		$	3			$	-

Quantitative information about unobservable inputs used in Level 3 fair value measurements is presented below:

 

Valuation Technique

Unobservable Input

As at       June 30, 2015

As at   December 31, 2014

Risk Management - Power

Discounted Cash Flow

Forward prices ($/Megawatt Hour)

$

44.50 - $56.96

$

40.70 - $48.50

A 10 percent increase or decrease in estimated forward power prices would cause a corresponding $6 million ($5 million as at December 31, 2014) increase or decrease to net risk management assets and liabilities.

 

Notes to Condensed Consolidated Financial Statements Prepared in accordance with U.S. GAAP in US$

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Q2 Report  |  For the period ended June 30, 2015

 

Notes to Condensed Consolidated Financial Statements  (unaudited)

(All amounts in $ millions unless otherwise specified)

 

21.  Financial Instruments and Risk Management

A)  Financial Instruments

Encana’s financial assets and liabilities are recognized in cash and cash equivalents, accounts receivable and accrued revenues, cash in reserve, accounts payable and accrued liabilities, risk management assets and liabilities and long-term debt.

B)  Risk Management Assets and Liabilities

Risk management assets and liabilities arise from the use of derivative financial instruments and are measured at fair value. See Note 20 for a discussion of fair value measurements.

 

Unrealized Risk Management Position		As at June 30, 2015				As at December 31, 2014
Risk Management Assets
Current		$	330			$	707
Long-term			11				65
			341				772
Risk Management Liabilities
Current			26				20
Long-term			15				7
			41				27
Net Risk Management Assets		$	300			$	745

Commodity Price Positions as at June 30, 2015

 

		Notional Volumes				Term		Average Price				Fair Value
Natural Gas Contracts
Fixed Price Contracts
NYMEX Fixed Price			1,000    MMcf/d			2015			4.29    US$/Mcf			$	255
Basis Contracts (1)						2015-2018							54
Other Financial Positions													-
Natural Gas Fair Value Position													309
Crude Oil Contracts
Fixed Price Contracts
WTI Fixed Price			59.4    Mbbls/d			2015			61.96    US$/bbl				17
WTI Fixed Price			38.0    Mbbls/d			2016			62.83    US$/bbl				11
Basis Contracts (2)						2015-2016							(27	)
Crude Oil Fair Value Position													1
Power Purchase Contracts
Fair Value Position													(10	)
Total Fair Value Position												$	300

 

(1)

Encana has entered into swaps to protect against widening natural gas price differentials between benchmark and regional sales prices. These basis swaps are priced using differentials determined as a percentage of NYMEX.

 

(2)

Encana has entered into swaps to protect against widening Brent and Midland differentials to WTI. These basis swaps are priced using fixed price differentials.

 

		Notes to Condensed Consolidated Financial Statements Prepared in accordance with U.S. GAAP in US$

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Q2 Report  |  For the period ended June 30, 2015

 

Notes to Condensed Consolidated Financial Statements  (unaudited)

(All amounts in $ millions unless otherwise specified)

 

21.  Financial Instruments and Risk Management (continued)

B)  Risk Management Assets and Liabilities (continued)

 

Earnings Impact of Realized and Unrealized Gains (Losses) on Risk Management Positions

 

		Realized Gain (Loss)
		Three Months Ended June 30,								Six Months Ended June 30,
		2015				2014				2015				2014
Revenues, Net of Royalties		$	164			$	(99	)		$	409			$	(239	)
Transportation and Processing			(3	)			(3	)			(8	)			(4	)
Gain (Loss) on Risk Management		$	161			$	(102	)		$	401			$	(243	)
		Unrealized Gain (Loss)
		Three Months Ended June 30,								Six Months Ended June 30,
		2015				2014				2015				2014
Revenues, Net of Royalties		$	(293	)		$	7			$	(421	)		$	(277	)
Transportation and Processing			15				2				7				1
Gain (Loss) on Risk Management		$	(278	)		$	9			$	(414	)		$	(276	)

Reconciliation of Unrealized Risk Management Positions from January 1 to June 30

 

		2015								2014
		Fair Value				Total Unrealized Gain (Loss)				Total Unrealized Gain (Loss)
Fair Value of Contracts, Beginning of Year		$	745
Change in Fair Value of Contracts in Place at Beginning of Year
and Contracts Entered into During the Period			(13	)		$	(13	)		$	(519	)
Settlement of Athlon Crude Oil Contracts from Business Combination			(31	)
Fair Value of Contracts Realized During the Period			(401	)			(401	)			243
Fair Value of Contracts, End of Period		$	300			$	414	)		$	(276	)

C)  Risks Associated with Financial Assets and Liabilities

The Company is exposed to financial risks including market risks (such as commodity prices, foreign exchange and interest rates), credit risk and liquidity risk. Future cash flows may fluctuate due to movement in market prices and the exposure to credit and liquidity risks.

Commodity Price Risk

Commodity price risk arises from the effect fluctuations in future commodity prices may have on future cash flows. To partially mitigate exposure to commodity price risk, the Company has entered into various derivative financial instruments. The use of these derivative instruments is governed under formal policies and is subject to limits established by the Board of Directors. The Company’s policy is to not use derivative financial instruments for speculative purposes.

Natural Gas - To partially mitigate natural gas commodity price risk, the Company uses contracts such as NYMEX-based swaps and options. Encana also enters into basis swaps to manage against widening price differentials between various production areas and various sales points.

Crude Oil - To partially mitigate against crude oil commodity price risk including widening price differentials between North American and world prices, the Company has entered into fixed price contracts and basis swaps.

Power - The Company has entered into Canadian dollar denominated derivative contracts to manage its electricity consumption costs.

 

Notes to Condensed Consolidated Financial Statements Prepared in accordance with U.S. GAAP in US$

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Q2 Report  |  For the period ended June 30, 2015

 

Notes to Condensed Consolidated Financial Statements  (unaudited)

(All amounts in $ millions unless otherwise specified)

 

21.  Financial Instruments and Risk Management (continued)

C)  Risks Associated with Financial Assets and Liabilities (continued)

Commodity Price Risk (continued)

 

The table below summarizes the sensitivity of the fair value of the Company’s risk management positions to fluctuations in commodity prices, with all other variables held constant. The Company has used a 10 percent variability to assess the potential impact of commodity price changes. Fluctuations in commodity prices could have resulted in unrealized gains (losses) impacting pre-tax net earnings for the six months ended June 30 as follows:

 

		2015								2014
		10% Price Increase				10% Price Decrease				10% Price Increase				10% Price Decrease
Natural Gas Price		$	(39)			$	39			$	(300)			$	300
Crude Oil Price			(150)				150				(48)				48
Power Price			6				(6)				7				(7)

Credit Risk

Credit risk arises from the potential that the Company may incur a loss if a counterparty to a financial instrument fails to meet its obligation in accordance with agreed terms. This credit risk exposure is mitigated through the use of Board-approved credit policies governing the Company’s credit portfolio including credit practices that limit transactions according to counterparties’ credit quality. Mitigation strategies may include master netting arrangements, requesting collateral and/or transacting credit derivatives. The Company executes commodity derivative financial instruments under master agreements that have netting provisions that provide for offsetting payables against receivables. As at June 30, 2015, the Company had no significant collateral balances posted or received and there were no credit derivatives in place.

As at June 30, 2015, cash equivalents include high-grade, short-term securities, placed primarily with financial institutions and companies with strong investment grade ratings. Any foreign currency agreements entered into are with major financial institutions in Canada and the U.S. or with counterparties having investment grade credit ratings.

A substantial portion of the Company’s accounts receivable are with customers in the oil and gas industry and are subject to normal industry credit risks. As at June 30, 2015, approximately 88 percent (94 percent as at December 31, 2014) of Encana’s accounts receivable and financial derivative credit exposures were with investment grade counterparties.

As at June 30, 2015, Encana had four counterparties (three counterparties as at December 31, 2014) whose net settlement position individually accounted for more than 10 percent of the fair value of the outstanding in-the-money net risk management contracts by counterparty. As at June 30, 2015, these counterparties accounted for 20 percent, 18 percent, 16 percent and 10 percent (16 percent, 16 percent and 15 percent as at December 31, 2014) of the fair value of the outstanding in-the-money net risk management contracts.

Liquidity Risk

Liquidity risk arises from the potential that the Company will encounter difficulties in meeting a demand to fund its financial liabilities as they come due. The Company manages liquidity risk using cash and debt management programs.

The Company has access to cash equivalents and a range of funding alternatives at competitive rates through committed revolving bank credit facilities and debt and equity capital markets. As at June 30, 2015, the Company had committed revolving bank credit facilities totaling $3.8 billion which include C$3.5 billion ($2.8 billion) on a revolving bank credit facility for Encana and $1.0 billion on a revolving bank credit facility for a U.S. subsidiary, the latter of which remains unused. Of the C$3.5 billion ($2.8 billion) revolving bank credit facility, $1.4 billion was fully supporting the U.S. Commercial Paper Program and $1.4 billion remained unused.

Encana also has accessible capacity under a shelf prospectus for up to $4.9 billion, or the equivalent in foreign currencies, the availability of which is dependent on market conditions, to issue debt and/or equity securities in Canada and/or the U.S. The shelf prospectus expires in July 2016.

The Company believes it has sufficient funding through the use of these facilities to meet foreseeable borrowing requirements.

 

		Notes to Condensed Consolidated Financial Statements Prepared in accordance with U.S. GAAP in US$

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Q2 Report  |  For the period ended June 30, 2015

 

Notes to Condensed Consolidated Financial Statements  (unaudited)

(All amounts in $ millions unless otherwise specified)

 

21.  Financial Instruments and Risk Management (continued)

C)  Risks Associated with Financial Assets and Liabilities (continued)

Liquidity Risk (continued)

 

The Company minimizes its liquidity risk by managing its capital structure. The Company’s capital structure consists of shareholders’ equity plus long-term debt, including the current portion. The Company’s objectives when managing its capital structure are to maintain financial flexibility to preserve Encana’s access to capital markets and its ability to meet financial obligations and to finance internally generated growth as well as potential acquisitions. To manage the capital structure, the Company may adjust capital spending, adjust dividends paid to shareholders, issue new shares, issue new debt or repay existing debt.

The timing of expected cash outflows relating to financial liabilities is outlined in the table below:

 

		Less Than 1 Year				1 - 3 Years				4 - 5 Years				6 - 9 Years				Thereafter				Total
Accounts Payable and Accrued Liabilities		$	1,744			$	-			$	-			$	-			$	-			$	1,744
Risk Management Liabilities			26				15				-				-				-				41
Long-Term Debt (1)			306				612				2,466				1,599				6,271				11,254

 

(1)	Principal and interest.

Included in Encana’s long-term debt obligations of $11,254 million at June 30, 2015 are $1,397 million in principal obligations for revolving credit and term loan borrowings related to U.S. Commercial Paper. These amounts are fully supported and Management expects they will continue to be supported by revolving credit facilities that have no repayment requirements within the next year. The revolving credit facilities are fully revolving for a period of up to five years. Based on the current maturity dates of the credit facilities, these amounts are included in cash outflows for the period disclosed as 4 - 5 Years. Further information on Long-Term Debt is contained in Note 10.

Foreign Exchange Risk

Foreign exchange risk arises from changes in foreign exchange rates that may affect the fair value or future cash flows of the Company’s financial assets or liabilities. As Encana operates primarily in North America, fluctuations in the exchange rate between the U.S. and Canadian dollars can have a significant effect on the Company’s reported results. Encana’s financial results are consolidated in Canadian dollars; however, the Company reports its results in U.S. dollars as most of its revenue is closely tied to the U.S. dollar and to facilitate a more direct comparison to other North American oil and gas companies. As the effects of foreign exchange fluctuations are embedded in the Company’s results, the total effect of foreign exchange fluctuations is not separately identifiable.

As at June 30, 2015, Encana had $6.1 billion in U.S. dollar debt issued from Canada that was subject to foreign exchange exposure. As at December 31, 2014, Encana had $6.7 billion in debt that was subject to foreign exchange exposure and $0.6 billion that was not subject to foreign exchange exposure. To mitigate the exposure to the fluctuating U.S./Canadian dollar exchange rate, Encana may enter into foreign exchange derivatives. There were no foreign exchange derivatives outstanding as at June 30, 2015.

Encana’s foreign exchange (gain) loss primarily includes foreign exchange gains and losses on the translation and settlement of U.S. dollar denominated debt issued from Canada, unrealized foreign exchange gains and losses on the translation of U.S. dollar denominated risk management assets and liabilities held in Canada, foreign exchange gains and losses on the translation and settlement of foreign denominated intercompany balances and foreign exchange gains and losses on U.S. dollar denominated cash and short-term investments held in Canada. A $0.01 change in the U.S. to Canadian dollar exchange rate would have resulted in a $50 million change in foreign exchange (gain) loss as at June 30, 2015 (2014 - $46 million).

Interest Rate Risk

Interest rate risk arises from changes in market interest rates that may affect the fair value or future cash flows from the Company’s financial assets or liabilities. The Company may partially mitigate its exposure to interest rate changes by holding a mix of both fixed and floating rate debt and may also enter into interest rate derivatives to partially mitigate effects of fluctuations in market interest rates. There were no interest rate derivatives outstanding as at June 30, 2015.

As at June 30, 2015, the Company had floating rate debt of $1,397 million. Accordingly, the sensitivity in net earnings for each one percent change in interest rates on floating rate debt was $10 million (2014 - nil).

 

Notes to Condensed Consolidated Financial Statements Prepared in accordance with U.S. GAAP in US$

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Q2 Report  |  For the period ended June 30, 2015

 

Notes to Condensed Consolidated Financial Statements  (unaudited)

(All amounts in $ millions unless otherwise specified)

 

22.  Commitments and Contingencies

Commitments

The following table outlines the Company’s commitments as at June 30, 2015:

 

		Expected Future Payments
(undiscounted)		2015				2016				2017				2018				2019				Thereafter				Total
Transportation and Processing		$	427			$	817			$	800			$	816			$	697			$	3,253			$	6,810
Drilling and Field Services			125				136				102				51				15				16				445
Operating Leases			18				30				25				24				11				24				132
Total		$	570			$	983			$	927			$	891			$	723			$	3,293			$	7,387

Included within transportation and processing in the table above are certain commitments associated with midstream service agreements with VMLP as described in Note 16.

Contingencies

Encana is involved in various legal claims and actions arising in the course of the Company’s operations. Although the outcome of these claims cannot be predicted with certainty, the Company does not expect these matters to have a material adverse effect on Encana’s financial position, cash flows or results of operations. If an unfavourable outcome were to occur, there exists the possibility of a material adverse impact on the Company’s consolidated net earnings or loss in the period in which the outcome is determined. Accruals for litigation and claims are recognized if the Company determines that the loss is probable and the amount can be reasonably estimated. The Company believes it has made adequate provision for such legal claims.

 

		Notes to Condensed Consolidated Financial Statements Prepared in accordance with U.S. GAAP in US$

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Q2 Report  |  For the period ended June 30, 2015

 

Supplemental Financial Information (unaudited)

Financial Results

 

		2015												2014
($ millions, except per share amounts)		Year-to- date				Q2				Q1				Year				Q4				Q3				Q2 Year- to-date				Q2				Q1
Cash Flow (1)			676				181				495				2,934				377				807				1,750				656				1,094
Per share - Diluted (4)			0.85				0.22				0.65				3.96				0.51				1.09				2.36				0.89				1.48
Operating Earnings (Loss) (2,3)			(148	)			(167	)			19				1,002				35				281				686				171				515
Per share - Diluted (4)			(0.19	)			(0.20	)			0.03				1.35				0.05				0.38				0.93				0.23				0.70
Net Earnings (Loss) Attributable to Common Shareholders			(3,317	)			(1,610	)			(1,707	)			3,392				198				2,807				387				271				116
Per share - Diluted (4)			(4.15	)			(1.91	)			(2.25	)			4.58				0.27				3.79				0.52				0.37				0.16
Effective Tax Rate using Canadian Statutory Rate			26.4%												25.7%
Foreign Exchange Rates (US$ per C$1) Average			0.810				0.813				0.806				0.905				0.881				0.918				0.912				0.917				0.906
Period end			0.802				0.802				0.789				0.862				0.862				0.892				0.937				0.937				0.905
Cash Flow Summary
Cash From (Used in) Operating Activities			780				298				482				2,667				261				696				1,710				767				943
Deduct (Add back):
Net change in other assets and liabilities			-				7				(7	)			(43	)			(15	)			(11	)			(17	)			(8	)			(9	)
Net change in non-cash working capital			104				110				(6	)			(9	)			(141	)			155				(23	)			119				(142	)
Cash tax on sale of assets			-				-				-				(215	)			40				(255	)			-				-				-
Cash Flow (1)			676				181				495				2,934				377				807				1,750				656				1,094
Operating Earnings Summary
Net Earnings (Loss) Attributable to Common Shareholders			(3,317	)			(1,610	)			(1,707	)			3,392				198				2,807				387				271				116
After-tax (addition) deduction:
Unrealized hedging gain (loss)			(285	)			(187	)			(98	)			306				341				160				(195	)			8				(203	)
Impairments			(2,550	)			(1,328	)			(1,222	)			-				-				-				-				-				-
Restructuring charges (3)			(20	)			(10	)			(10	)			(24	)			(4	)			(5	)			(15	)			(5	)			(10	)
Non-operating foreign exchange gain (loss)			(394	)			114				(508	)			(407	)			(151	)			(218	)			(38	)			156				(194	)
Gain (loss) on divestitures			11				1				10				2,523				(11	)			2,399				135				135				-
Income tax adjustments			69				(33	)			102				(8	)			(12	)			190				(186	)			(194	)			8
Operating Earnings (Loss) (2,3)			(148	)			(167	)			19				1,002				35				281				686				171				515

 

(1)

Cash Flow is a non-GAAP measure defined as cash from operating activities excluding net change in other assets and liabilities, net change in non-cash working capital and cash tax on sale of assets.

 

(2)

Operating Earnings (Loss) is a non-GAAP measure defined as net earnings (loss) attributable to common shareholders excluding non-recurring or non-cash items that Management believes reduces the comparability of the Company’s financial performance between periods. These after-tax items may include, but are not limited to, unrealized hedging gains/losses, impairments, restructuring charges, non-operating foreign exchange gains/losses, gains/losses on divestitures, income taxes related to divestitures and adjustments to normalize the effect of income taxes calculated using the estimated annual effective income tax rate.

 

(3)

In continued support of Encana’s strategy, organizational structure changes were formalized in Q2 2015 and resulted in a revision to the Q1 2015 Operating Earnings to exclude restructuring charges incurred in the first quarter.

 

(4)

Net earnings (loss) attributable to common shareholders, operating earnings (loss) and cash flow per common share are calculated using the weighted average number of Encana common shares outstanding as follows:

		2015												2014
(millions)		Year-to- date				Q2				Q1				Year				Q4				Q3				Q2 Year- to-date				Q2				Q1
Weighted Average Common Shares Outstanding
Basic			799.5				841.2				757.8				741.0				741.1				741.1				741.0				741.0				741.0
Diluted			799.5				841.2				757.8				741.0				741.1				741.1				741.0				741.0				741.0

 

Supplemental Information Prepared in US$

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Q2 Report  |  For the period ended June 30, 2015

 

Supplemental Financial & Operating Information (unaudited)

Financial Metrics

 

		2015												2014
		Year-to- date												Year
Debt to Debt Adjusted Cash Flow			2.5x												2.1x
Debt to Adjusted Capitalization			28%												30%
The financial metrics disclosed above are non-GAAP measures monitored by Management as indicators of the Company’s overall financial strength. These non-GAAP measures are defined and calculated in the Non-GAAP Measures section of Encana’s Management’s Discussion and Analysis.
Net Capital Investment
		2015												2014
($ millions)		Year-to- date				Q2				Q1				Year				Q4				Q3				Q2 Year- to-date				Q2				Q1
Capital Investment
Canadian Operations			265				114				151				1,226				302				293				631				350				281
USA Operations			1,211				628				583				1,285				548				305				432				206				226
Market Optimization			-				-				-				-				-				(2	)			2				1				1
Corporate & Other			3				1				2				15				7				2				6				3				3
Capital Investment			1,479				743				736				2,526				857				598				1,071				560				511
Net Acquisitions & (Divestitures)			(978)				(140	)			(838	)			(1,329	)			50				(2,007	)			628				652				(24	)
Net Capital Investment			501				603				(102	)			1,197				907				(1,409	)			1,699				1,212				487
Capital Investment
		2015												2014
($ millions)		Year-to- date				Q2				Q1				Year				Q4				Q3				Q2 Year- to-date				Q2				Q1
Capital Investment
Montney (1)			127				48				79				781				159				204				418				210				208
Duvernay			127				57				70				328				118				58				152				81				71
Eagle Ford			372				175				197				274				149				113				12				12				-
Permian			542				325				217				117				117				-				-				-				-
DJ Basin			144				56				88				277				81				68				128				69				59
San Juan			59				23				36				287				96				89				102				50				52
			1,371				684				687				2,064				720				532				812				422				390
Other Upstream Operations (1, 2)			105				58				47				447				130				66				251				134				117
Market Optimization			-				-				-				-				-				(2	)			2				1				1
Corporate & Other			3				1				2				15				7				2				6				3				3
Capital Investment			1,479				743				736				2,526				857				598				1,071				560				511

 

(1)

Montney has been realigned to include certain capital investments which were previously reported in Other Upstream Operations.

 

(2)

Other Upstream Operations includes capital investment for Encana’s base production properties as well as capital investment for prospective plays which are under appraisal, including the Tuscaloosa Marine Shale (“TMS”). 2015 year-to-date capital investment for the TMS was $42 million (2014 year-to-date - $47 million).

 

		Supplemental Information Prepared in US$

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Q2 Report  |  For the period ended June 30, 2015

 

Supplemental Financial & Operating Information (unaudited)

 

Production Volumes - After Royalties

 

		2015												2014
(average)		Year-to- date				Q2				Q1				Year				Q4				Q3				Q2 Year- to-date				Q2				Q1
Natural Gas (MMcf/d)			1,712				1,568				1,857				2,350				1,861				2,199				2,675				2,541				2,809
Oil (Mbbls/d)			82.7				86.2				79.2				49.4				68.8				62.1				33.1				34.2				32.1
NGLs (Mbbls/d)			41.3				41.1				41.5				37.4				37.6				41.9				34.9				34.0				35.8
Oil & NGLs (Mbbls/d)			124.0				127.3				120.7				86.8				106.4				104.0				68.0				68.2				67.9
Total (MBOE/d)			409.3				388.7				430.1				478.5				416.7				470.6				513.8				491.8				536.1
Production Volumes - After Royalties
		2015												2014
(average)		Year-to- date				Q2				Q1				Year				Q4				Q3				Q2 Year- to-date				Q2				Q1
Natural Gas (MMcf/d)
Canadian Operations			1,004				881				1,128				1,378				1,111				1,374				1,516				1,463				1,568
USA Operations			708				687				729				972				750				825				1,159				1,078				1,241
			1,712				1,568				1,857				2,350				1,861				2,199				2,675				2,541				2,809
Oil (Mbbls/d)
Canadian Operations			6.5				6.5				6.6				13.6				9.4				14.7				15.1				13.9				16.4
USA Operations			76.2				79.7				72.6				35.8				59.4				47.4				18.0				20.3				15.7
			82.7				86.2				79.2				49.4				68.8				62.1				33.1				34.2				32.1
NGLs (Mbbls/d)
Canadian Operations			20.5				19.8				21.2				23.6				18.8				27.6				24.1				23.5				24.6
USA Operations			20.8				21.3				20.3				13.8				18.8				14.3				10.8				10.5				11.2
			41.3				41.1				41.5				37.4				37.6				41.9				34.9				34.0				35.8
Oil & NGLs (Mbbls/d)
Canadian Operations			27.0				26.3				27.8				37.2				28.2				42.3				39.2				37.4				41.0
USA Operations			97.0				101.0				92.9				49.6				78.2				61.7				28.8				30.8				26.9
			124.0				127.3				120.7				86.8				106.4				104.0				68.0				68.2				67.9
Total (MBOE/d)
Canadian Operations			194.4				173.2				215.8				266.9				213.4				271.4				291.8				281.4				302.4
USA Operations			214.9				215.5				214.3				211.6				203.3				199.2				222.0				210.4				233.7
			409.3				388.7				430.1				478.5				416.7				470.6				513.8				491.8				536.1
Oil & NGLs Production Volumes - After Royalties
		2015												2014
(average Mbbls/d)		Year-to- date				% of Total								Year				% of Total
Oil			82.7				67								49.4				57
Plant Condensate			14.0				11								12.0				14
Butane			6.7				5								6.8				8
Propane			11.1				9								10.2				11
Ethane			9.5				8								8.4				10
			124.0				100								86.8				100

 

Supplemental Information Prepared in US$

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Q2 Report  |  For the period ended June 30, 2015

 

Supplemental Financial & Operating Information (unaudited)

 

Results of Operations

Product and Operational Information, Including the Impact of Realized Financial Hedging

 

		2015												2014
($ millions)		Year-to- date				Q2				Q1				Year				Q4				Q3				Q2 Year- to-date				Q2				Q1
Natural Gas - Canadian Operations
Revenues, Net of Royalties, excluding Hedging			589				193				396				2,468				402				480				1,586				569				1,017
Realized Financial Hedging Gain (Loss)			260				106				154				(74	)			25				20				(119	)			(44	)			(75	)
Expenses
Production and mineral taxes			-				-				-				5				2				1				2				-				2
Transportation and processing			321				158				163				773				177				186				410				209				201
Operating			76				40				36				279				57				66				156				72				84
Operating Cash Flow			452				101				351				1,337				191				247				899				244				655
Natural Gas - USA Operations
Revenues, Net of Royalties, excluding Hedging			341				146				195				1,640				274				307				1,059				463				596
Realized Financial Hedging Gain (Loss)			112				58				54				(85	)			13				10				(108	)			(43	)			(65	)
Expenses
Production and mineral taxes			9				5				4				44				11				(10	)			43				14				29
Transportation and processing			293				142				151				651				149				162				340				177				163
Operating			95				46				49				235				52				50				133				65				68
Operating Cash Flow			56				11				45				625				75				115				435				164				271
Natural Gas - Total Operations
Revenues, Net of Royalties, excluding Hedging			930				339				591				4,108				676				787				2,645				1,032				1,613
Realized Financial Hedging Gain (Loss)			372				164				208				(159	)			38				30				(227	)			(87	)			(140	)
Expenses
Production and mineral taxes			9				5				4				49				13				(9	)			45				14				31
Transportation and processing			614				300				314				1,424				326				348				750				386				364
Operating			171				86				85				514				109				116				289				137				152
Operating Cash Flow			508				112				396				1,962				266				362				1,334				408				926
Oil & NGLs - Canadian Operations
Revenues, Net of Royalties, excluding Hedging			168				91				77				872				149				251				472				227				245
Realized Financial Hedging Gain (Loss)			(3	)			(5	)			2				18				24				(1	)			(5	)			(5	)			-
Expenses
Production and mineral taxes			-				-				-				10				-				3				7				4				3
Transportation and processing			27				13				14				62				16				16				30				16				14
Operating			11				5				6				28				10				8				10				4				6
Operating Cash Flow			127				68				59				790				147				223				420				198				222
Oil & NGLs - USA Operations
Revenues, Net of Royalties, excluding Hedging			709				414				295				1,258				412				452				394				215				179
Realized Financial Hedging Gain (Loss)			43				5				38				60				65				1				(6	)			(6	)			-
Expenses
Production and mineral taxes			36				21				15				74				23				23				28				15				13
Transportation and processing			6				2				4				7				3				4				-				-				-
Operating			179				104				75				115				51				44				20				12				8
Operating Cash Flow			531				292				239				1,122				400				382				340				182				158
Oil & NGLs - Total Operations
Revenues, Net of Royalties, excluding Hedging			877				505				372				2,130				561				703				866				442				424
Realized Financial Hedging Gain (Loss)			40				-				40				78				89				-				(11	)			(11	)			-
Expenses
Production and mineral taxes			36				21				15				84				23				26				35				19				16
Transportation and processing			33				15				18				69				19				20				30				16				14
Operating			190				109				81				143				61				52				30				16				14
Operating Cash Flow			658				360				298				1,912				547				605				760				380				380

 

		Supplemental Information Prepared in US$

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Q2 Report  |  For the period ended June 30, 2015

 

Supplemental Oil and Gas Operating Statistics (unaudited)

Operating Statistics - After Royalties

Per-unit Results, Excluding the Impact of Realized Financial Hedging

 

		2015												2014
		Year-to- date				Q2				Q1				Year				Q4				Q3				Q2 Year- to-date				Q2				Q1
Natural Gas - Canadian Operations ($/Mcf)
Price (1)			3.23				2.39				3.89				4.89				3.93				3.78				5.77				4.27				7.17
Production and mineral taxes			-				-				-				0.01				0.01				0.01				0.01				-				0.01
Transportation and processing			1.76				1.97				1.60				1.53				1.73				1.47				1.49				1.57				1.42
Operating			0.42				0.49				0.35				0.55				0.55				0.52				0.57				0.55				0.59
Netback			1.05				(0.07	)			1.94				2.80				1.64				1.78				3.70				2.15				5.15
Natural Gas - USA Operations ($/Mcf)
Price			2.66				2.33				2.97				4.62				3.95				4.05				5.05				4.72				5.34
Production and mineral taxes			0.07				0.08				0.06				0.12				0.17				(0.14	)			0.21				0.15				0.26
Transportation and processing			2.29				2.27				2.30				1.83				2.16				2.13				1.62				1.80				1.46
Operating			0.75				0.74				0.75				0.66				0.75				0.65				0.64				0.67				0.61
Netback			(0.45	)			(0.76	)			(0.14	)			2.01				0.87				1.41				2.58				2.10				3.01
Natural Gas - Total Operations ($/Mcf)
Price (2)			3.00				2.37				3.53				4.78				3.94				3.88				5.46				4.46				6.37
Production and mineral taxes			0.03				0.04				0.02				0.06				0.08				(0.05	)			0.09				0.06				0.12
Transportation and processing			1.98				2.10				1.88				1.66				1.90				1.72				1.55				1.67				1.44
Operating			0.55				0.60				0.51				0.60				0.63				0.57				0.60				0.60				0.60
Netback			0.44				(0.37	)			1.12				2.46				1.33				1.64				3.22				2.13				4.21
Oil & NGLs - Canadian Operations ($/bbl)
Price			34.53				38.57				30.65				64.16				57.50				64.79				66.25				66.13				66.36
Production and mineral taxes			0.02				-				0.04				0.71				0.10				0.67				0.95				1.12				0.80
Transportation and processing			5.64				5.46				5.82				4.52				5.92				4.21				4.18				4.60				3.80
Operating			2.12				1.91				2.31				2.09				4.00				2.05				1.42				1.06				1.75
Netback			26.75				31.20				22.48				56.84				47.48				57.86				59.70				59.35				60.01
Oil & NGLs - USA Operations ($/bbl)
Price			40.43				45.21				35.18				69.54				57.30				79.43				75.67				77.46				73.61
Production and mineral taxes			2.04				2.26				1.80				4.10				3.16				4.18				5.32				5.19				5.46
Transportation and processing			0.33				0.24				0.43				0.39				0.49				0.63				-				-				-
Operating			10.18				11.28				8.96				6.36				7.11				7.80				3.77				4.29				3.16
Netback			27.88				31.43				23.99				58.69				46.54				66.82				66.58				67.98				64.99
Oil & NGLs - Total Operations ($/bbl)
Price			39.14				43.83				34.13				67.24				57.35				73.48				70.24				71.23				69.23
Production and mineral taxes			1.60				1.79				1.40				2.65				2.35				2.75				2.80				2.95				2.65
Transportation and processing			1.49				1.32				1.67				2.16				1.93				2.09				2.41				2.53				2.30
Operating			8.41				9.35				7.43				4.54				6.29				5.46				2.42				2.51				2.31
Netback			27.64				31.37				23.63				57.89				46.78				63.18				62.61				63.24				61.97
Total Operations Netback - Canadian Operations ($/BOE)
Price			21.50				18.05				24.30				34.21				28.06				29.21				38.85				31.02				46.20
Production and mineral taxes			0.01				-				0.02				0.15				0.09				0.15				0.17				0.16				0.18
Transportation and processing			9.90				10.85				9.12				8.55				9.79				8.10				8.30				8.76				7.87
Operating			2.44				2.80				2.14				3.14				3.39				2.96				3.14				2.98				3.29
Netback			9.15				4.40				13.02				22.37				14.79				18.00				27.24				19.12				34.86
Total Operations Netback - USA Operations ($/BOE)
Price			26.99				28.61				25.34				37.53				36.64				41.38				36.18				35.48				36.82
Production and mineral taxes			1.15				1.33				0.97				1.53				1.84				0.72				1.76				1.51				1.99
Transportation and processing			7.68				7.34				8.02				8.52				8.17				9.03				8.45				9.23				7.75
Operating			7.05				7.66				6.44				4.53				5.51				5.12				3.81				4.05				3.60
Netback			11.11				12.28				9.91				22.95				21.12				26.51				22.16				20.69				23.48
Total Operations Netback ($/BOE)
Price			24.38				23.90				24.82				35.67				32.25				34.36				37.70				32.93				42.12
Production and mineral taxes			0.61				0.73				0.49				0.76				0.94				0.39				0.86				0.74				0.97
Transportation and processing			8.73				8.91				8.57				8.54				9.00				8.50				8.37				8.96				7.82
Operating (3)			4.86				5.50				4.27				3.76				4.43				3.87				3.43				3.44				3.43
Netback			10.18				8.76				11.49				22.61				17.88				21.60				25.04				19.79				29.90

 

(1)

Canadian Operations price reflects Deep Panuke price for 2015 year-to-date of $9.40/Mcf on natural gas production volumes of 107 MMcf/d. Excluding the impact of the Deep Panuke operations, the natural gas price for 2015 year-to-date is $2.50/Mcf.

(2)

Excluding the impact of the Deep Panuke operations, the natural gas price for 2015 year-to-date is $2.57/Mcf.

(3)

2015 year-to-date operating expense includes costs related to long-term incentives of $0.01/BOE (2014 year to date - costs of $0.30/BOE).

 

Supplemental Information Prepared in US$

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Q2 Report  |  For the period ended June 30, 2015

 

Supplemental Oil and Gas Operating Statistics (unaudited)

Operating Statistics - After Royalties (continued)

 

Impact of Realized Financial Hedging

 

		2015												2014
		Year-to- date				Q2				Q1				Year				Q4				Q3				Q2 Year- to-date				Q2				Q1
Natural Gas ($/Mcf)
Canadian Operations			1.43				1.32				1.52				(0.15	)			0.24				0.16				(0.43	)			(0.33	)			(0.53	)
USA Operations			0.88				0.93				0.82				(0.24	)			0.19				0.12				(0.51	)			(0.44	)			(0.58	)
Total Operations			1.20				1.15				1.25				(0.19	)			0.22				0.15				(0.47	)			(0.38	)			(0.55	)
Oil & NGLs ($/bbl)
Canadian Operations			(0.68	)			(2.21	)			0.78				1.36				9.35				(0.31	)			(0.63	)			(1.22	)			(0.09	)
USA Operations			2.45				0.52				4.58				3.29				8.94				0.25				(1.21	)			(2.28	)			0.04
Total Operations			1.77				(0.05	)			3.70				2.46				9.05				0.02				(0.88	)			(1.70	)			(0.04	)
Total ($/BOE)
Canadian Operations			7.30				6.39				8.04				(0.57	)			2.49				0.78				(2.35	)			(1.89	)			(2.77	)
USA Operations			3.99				3.22				4.78				(0.33	)			4.15				0.58				(2.83	)			(2.57	)			(3.07	)
Total Operations			5.56				4.63				6.42				(0.46	)			3.30				0.70				(2.56	)			(2.18	)			(2.90	)
Per-unit Results, Including the Impact of Realized Financial Hedging
		2015												2014
		Year-to- date				Q2				Q1				Year				Q4				Q3				Q2 Year- to-date				Q2				Q1
Natural Gas Price ($/Mcf)
Canadian Operations			4.66				3.71				5.41				4.74				4.17				3.94				5.34				3.94				6.64
USA Operations			3.54				3.26				3.79				4.38				4.14				4.17				4.54				4.28				4.76
Total Operations			4.20				3.52				4.78				4.59				4.16				4.03				4.99				4.08				5.82
Natural Gas Netback ($/Mcf)
Canadian Operations			2.48				1.25				3.46				2.65				1.88				1.94				3.27				1.82				4.62
USA Operations			0.43				0.17				0.68				1.77				1.06				1.53				2.07				1.66				2.43
Total Operations			1.64				0.78				2.37				2.27				1.55				1.79				2.75				1.75				3.66
Oil & NGLs Price ($/bbl)
Canadian Operations			33.85				36.36				31.43				65.52				66.85				64.48				65.62				64.91				66.27
USA Operations			42.88				45.73				39.76				72.83				66.24				79.68				74.46				75.18				73.65
Total Operations			40.91				43.78				37.83				69.70				66.40				73.50				69.36				69.53				69.19
Oil & NGLs Netback ($/bbl)
Canadian Operations			26.07				28.99				23.26				58.20				56.83				57.55				59.07				58.13				59.92
USA Operations			30.33				31.95				28.57				61.98				55.48				67.07				65.37				65.70				65.03
Total Operations			29.41				31.32				27.33				60.35				55.83				63.20				61.73				61.54				61.93
Total Price ($/BOE)
Canadian Operations			28.80				24.44				32.34				33.64				30.55				29.99				36.50				29.13				43.43
USA Operations			30.98				31.83				30.12				37.20				40.79				41.96				33.35				32.91				33.75
Total Operations			29.94				28.53				31.24				35.21				35.55				35.06				35.14				30.75				39.22
Total Netback ($/BOE)
Canadian Operations			16.45				10.79				21.06				21.80				17.28				18.78				24.89				17.23				32.09
USA Operations			15.10				15.50				14.69				22.62				25.27				27.09				19.33				18.12				20.41
Total Operations			15.74				13.39				17.91				22.15				21.18				22.30				22.48				17.61				27.00

 

		Supplemental Information Prepared in US$

---

Q2 Report  |  For the period ended June 30, 2015

 

Supplemental Oil and Gas Operating Statistics (unaudited)

 

Results by Play

 

		2015												2014
		Year-to- date				Q2				Q1				Year				Q4				Q3				Q2 Year- to-date				Q2				Q1
Natural Gas Production (MMcf/d) - After Royalties
Canadian Operations
Montney (1)			701				685				717				639				687				644				612				604				620
Duvernay			17				17				16				11				12				15				9				9				8
Other Upstream Operations (2)
Wheatland (3)			94				76				111				292				249				291				314				305				324
Bighorn			2				-				4				158				(3	)			162				238				230				246
Deep Panuke			107				32				182				190				79				186				248				243				253
Other and emerging (1)			83				71				98				88				87				76				95				72				117
Total Canadian Operations			1,004				881				1,128				1,378				1,111				1,374				1,516				1,463				1,568
USA Operations
Eagle Ford			36				36				36				19				35				35				2				5				-
Permian			36				38				34				5				20				-				-				-				-
DJ Basin			52				55				49				43				49				38				42				43				40
San Juan			14				15				13				8				8				9				7				7				7
Other Upstream Operations (2)
Piceance			333				324				343				402				367				398				421				407				436
Haynesville			217				204				230				311				252				298				348				365				331
Jonah			-				-				-				100				-				-				203				124				282
East Texas			-				-				-				57				-				21				105				97				113
Other and emerging			20				15				24				27				19				26				31				30				32
Total USA Operations			708				687				729				972				750				825				1,159				1,078				1,241
Oil & NGLs Production (Mbbls/d) - After Royalties
Canadian Operations
Montney (1)			22.5				21.6				23.3				18.9				24.8				20.8				14.8				13.3				16.2
Duvernay			2.9				3.0				2.8				2.1				2.5				2.6				1.6				1.8				1.4
Other Upstream Operations (2)
Wheatland (3)			1.5				1.2				1.7				8.6				2.0				9.9				11.3				11.3				11.3
Bighorn			-				-				-				7.5				(1.5	)			8.7				11.5				11.0				12.1
Other and emerging (1)			0.1				0.5				-				0.1				0.4				0.3				-				-				-
Total Canadian Operations			27.0				26.3				27.8				37.2				28.2				42.3				39.2				37.4				41.0
USA Operations
Eagle Ford			37.9				39.8				36.0				19.8				36.1				37.6				2.5				5.0				-
Permian			28.1				29.5				26.7				3.5				13.8				-				-				-				-
DJ Basin			14.8				15.3				14.3				11.6				14.0				11.8				10.3				10.1				10.5
San Juan			6.6				6.4				6.7				3.9				5.6				3.5				3.3				3.9				2.7
Other Upstream Operations (2)
Piceance			3.7				3.7				3.7				5.0				4.3				4.8				5.4				5.3				5.4
Jonah			-				-				-				1.8				-				0.2				3.6				2.5				4.7
East Texas			-				-				-				0.5				-				-				1.1				1.0				1.2
Other and emerging			5.9				6.3				5.5				3.5				4.4				3.8				2.6				3.0				2.4
Total USA Operations			97.0				101.0				92.9				49.6				78.2				61.7				28.8				30.8				26.9

 

(1)

Montney has been realigned to include certain production volumes which were previously reported in Other and emerging.

(2)

Other Upstream Operations includes results from plays that are not part of the Company’s current strategic focus as well as prospective plays which are under appraisal, including the TMS which is reported in Other and emerging in the USA Operations.

(3)

Wheatland was previously presented as Clearwater.

 

Supplemental Information Prepared in US$

---

Q2 Report  |  For the period ended June 30, 2015

 

Supplemental Oil and Gas Operating Statistics (unaudited)

Results by Play (continued)

 

		2015												2014
		Year-to- date				Q2				Q1				Year				Q4				Q3				Q2 Year- to-date				Q2				Q1
Drilling Activity (net wells drilled)
Canadian Operations
Montney			14				6				8				79				14				15				50				23				27
Duvernay			7				1				6				24				5				7				12				6				6
Other Upstream Operations (1)
Wheatland (2)			71				-				71				174				84				24				66				-				66
Bighorn			-				-				-				1				-				1				-				-				-
Other and emerging			-				-				-				1				-				1				-				-				-
Total Canadian Operations			92				7				85				279				103				48				128				29				99
USA Operations
Eagle Ford			41				14				27				35				21				14				-				-				-
Permian			98				52				46				28				28				-				-				-				-
DJ Basin			15				2				13				64				15				17				32				14				18
San Juan			1				-				1				43				19				15				9				5				4
Other Upstream Operations (1)
Piceance			-				-				-				1				-				-				1				-				1
Haynesville			-				-				-				-				-				-				-				-				-
Jonah			-				-				-				18				-				-				18				6				12
East Texas			-				-				-				-				-				-				-				-				-
Other and emerging			3				-				3				15				5				4				6				4				2
Total USA Operations			158				68				90				204				88				50				66				29				37

 

(1)

Other Upstream Operations includes net wells drilled in plays that are not part of the Company’s current strategic focus as well as prospective plays which are under appraisal, including the TMS which is reported in Other and emerging in the USA Operations.

(2)

Wheatland was previously presented as Clearwater.

 

		Supplemental Information Prepared in US$

---