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 May 14, 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  x

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: May 14, 2015

 

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Form 6-K Exhibit Index

 

Exhibit No.
99.1		Interim Report to Shareholders for the period ended March 31, 2015, including the Unaudited Interim Condensed Consolidated Financial Statements and Management’s Discussion and Analysis for the said period.

Exhibit 99.1

 

2015 Q1 Report
For the period ending
March 31, 2015
encana

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Q1 Report  |  for the period ended March 31, 2015

 

 

 

Encana reports solid first quarter operating performance and continued liquids growth

 

 

On a reported basis, due primarily to a non-cash, after-tax ceiling test impairment and a non-operating foreign exchange loss, Encana recorded a net loss of $1.7 billion for the first quarter.

 

 

 

		First Quarter Report

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Q1 Report  |  for the period ended March 31, 2015

 

 

 

THIRD QUARTER OPERATIONAL HIGHLIGHTS

 

 

 

 

 

 

		First Quarter Report

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Q1 Report  |  for the period ended March 31, 2015

 

 

 

 

 

 

		First Quarter Report

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Q1 Report  |  for the period ended March 31, 2015

 

 

 

FIRST QUARTER HIGHLIGHTS

 

 

FINANCIAL SUMMARY

 

(for the period ended March 31) ($ millions, except per share amounts)		Q1 2015				Q1 2014
Cash flow1			495				1,094
Per share diluted			0.65				1.48
Operating earnings1			9				515
Per share diluted			0.01				0.70
EARNINGS RECONCILIATION SUMMARY
Net earnings attributable to common shareholders			(1,707	)			116
After-tax (addition) deduction:
Unrealized hedging gain (loss)			(98	)			(203	)
Impairments			(1,222	)			—
Restructuring charges			—				(10	)
Non-operating foreign exchange gain (loss)			(508	)			(194	)
Gain (loss) on divestitures			10				—
Income tax adjustments			102				8
Operating earnings1			9				515
Per share diluted			0.01				0.70

 

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

PRODUCTION SUMMARY

 

(for the period ended March 31) (after royalties)		Q1 2015				Q1 2014				% D
Natural gas (MMcf/d)			1,857				2,809				(34	)
Liquids (Mbbls/d)			120.7				67.9				78

NATURAL GAS AND LIQUIDS PRICES

 

		Q3 2014				Q3 2013
Natural Gas
NYMEX ($/MMBtu)			4.06				3.58
Encana realized gas price1 ($/Mcf)			4.03				4.00
Oil and NGL’s ($/bbl)
WTI			48.64				98.68
Encana realized NGLs price			37.83				69.19

 

(1)	Realized prices include the impact of financial hedging.

 

 

 

		First Quarter Report

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Q1 Report  |  for the period ended March 31, 2015

 

 

 

 

		First Quarter Report

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Q1 Report  |  for the period ended March 31, 2015

 

 

 

 

 

 

		First Quarter Report

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Q1 Report  |  for the period ended March 31, 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 March 31, 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 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 May 11, 2015.

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

Certain measures in this document do not have any standardized meaning as prescribed by U.S. GAAP and, therefore, are considered non-GAAP measures. Non-GAAP measures are commonly used in the oil and gas industry and by Encana to provide shareholders and potential investors with additional information regarding the Company’s liquidity and its ability to generate funds to finance its operations. Non-GAAP measures include: Cash Flow; Free Cash Flow; Operating Earnings; 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.

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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Q1 Report  |  for the period ended March 31, 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 March 31, 2015 can be found in the Results Overview section of this MD&A and in Note 20 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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Q1 Report  |  for the period ended March 31, 2015

 

 

 

Results Overview

Highlights

 

In the three months ended March 31, 2015, Encana reported:

 

•

Cash Flow of $495 million and Operating Earnings of $9 million.

 

•

Net Loss of $1,707 million, including an after-tax non-cash ceiling test impairment of $1,222 million.

 

•

Average realized natural gas prices, including financial hedges, of $4.78 per Mcf. Average realized oil prices, including financial hedges, of $46.17 per bbl. Average realized NGL prices of $21.92 per bbl.

 

•

Average natural gas production volumes of 1,857 MMcf/d and average oil and NGL production volumes of 120.7 Mbbls/d.

 

•

Dividends paid of $0.07 per share.

 

•

Cash and cash equivalents of $2,030 million at period end.

Significant developments for the Company during the three months ended March 31, 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.

 

•

Provided notice on March 5, 2015 to note holders that the Company would redeem its $700 million 5.90 percent notes due December 1, 2017 and its C$750 million 5.80 percent medium-term notes due January 18, 2018. On April 6, 2015, the Company used net proceeds from the Share Offering and cash on hand to complete the note redemptions.

 

•

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$455 million, after closing adjustments. 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 (“CRP”).

 

 

 

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

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Q1 Report  |  for the period ended March 31, 2015

 

 

 

Financial Results

 

 

		2015				2014																2013
($ millions, except as indicated)		Q1				Q4				Q3				Q2				Q1				Q4				Q3				Q2
Cash Flow (1)		$	495			$	377			$	807			$	656			$	1,094			$	677			$	660			$	665
$ per share - diluted			0.65				0.51				1.09				0.89				1.48				0.91				0.89				0.90
Operating Earnings (1)			9				35				281				171				515				226				150				247
$ per share - diluted			0.01				0.05				0.38				0.23				0.70				0.31				0.20				0.34
Net Earnings (Loss) Attributable to Common Shareholders			(1,707	)			198				2,807				271				116				(251	)			188				730
$ per share - basic & diluted			(2.25	)			0.27				3.79				0.37				0.16				(0.34	)			0.25				0.99
Revenues, Net of Royalties			1,249				2,254				2,285				1,588				1,892				1,423				1,392				1,984
Realized Hedging Gain (Loss), before tax			240				124				28				(102	)			(141	)			174				175				52
Unrealized Hedging Gain (Loss), before tax			(136	)			489				231				9				(285	)			(301	)			(128	)			469
Upstream Operating Cash Flow			702				821				982				800				1,315				901				794				788
Upstream Operating Cash Flow Excluding Realized Hedging (1)			454				694				952				898				1,455				728				622				737
Capital Investment			736				857				598				560				511				717				641				639
Net Acquisitions & (Divestitures) (2)			(838	)			50				(2,007	)			652				(24	)			(72	)			(51	)			(312	)
Free Cash Flow (1)			(241	)			(480	)			209				96				583				(40	)			19				26
Ceiling Test Impairments, after tax			(1,222	)			—				—				—				—				—				—				—
Gain (Loss) on Divestitures, after tax			10				(11	)			2,399				135				—				—				—				—
Production Volumes
Natural Gas (MMcf/d)			1,857				1,861				2,199				2,541				2,809				2,744				2,723				2,766
Oil & NGLs (Mbbls/d)
Oil			79.2				68.8				62.1				34.2				32.1				33.0				27.2				22.9
NGLs			41.5				37.6				41.9				34.0				35.8				33.0				31.0				24.7
Total Oil & NGLs			120.7				106.4				104.0				68.2				67.9				66.0				58.2				47.6
Total Production (MBOE/d)			430.1				416.7				470.6				491.8				536.1				523.4				512.1				508.6
Production Mix (%)
Natural Gas			72				74				78				86				87				87				89				91
Oil & NGLs			28				26				22				14				13				13				11				9

 

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

(2)	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 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.

 

 

 

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

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Q1 Report  |  for the period ended March 31, 2015

 

 

 

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 first quarter of 2015, the Company recognized an after-tax non-cash ceiling test impairment of $1,222 million in the U.S. cost centre. The non-cash ceiling test impairment 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 March 31, 2015 versus March 31, 2014

Cash Flow of $495 million decreased $599 million in the three months ended March 31, 2015 primarily due to the following significant items:

 

•

Average realized natural gas prices, excluding financial hedges, were $3.53 per Mcf compared to $6.37 per Mcf in 2014 reflecting lower benchmark prices. Lower realized natural gas prices decreased revenues $472 million. Average realized liquids prices, excluding financial hedges, were $34.13 per bbl compared to $69.23 per bbl in 2014 reflecting lower benchmark prices. Lower realized liquids prices decreased revenues $208 million.

 

•

Average natural gas production volumes of 1,857 MMcf/d decreased 952 MMcf/d from 2,809 MMcf/d in 2014 primarily due to divestitures during 2014, 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 $550 million. Average oil and NGL production volumes of 120.7 Mbbls/d increased 52.8 Mbbls/d from 67.9 Mbbls/d in 2014 primarily due to acquisitions during 2014 and successful drilling programs in oil and liquids rich natural gas plays, partially offset by divestitures during 2014. Higher oil and NGL volumes increased revenues $156 million.

 

•

Realized financial hedging gains before tax were $240 million compared to losses of $141 million in 2014.

 

•

Production and mineral taxes decreased $28 million primarily due to divestitures during 2014 and lower commodity prices, partially offset by acquisitions during 2014.

 

•

Transportation and processing expense decreased $39 million primarily due to divestitures during 2014 and the lower U.S./Canadian dollar exchange rate, partially offset by higher liquids volumes processed in Montney.

Operating Earnings of $9 million decreased $506 million primarily due to the items discussed in the Cash Flow section. Operating Earnings for the first quarter of 2015 were also impacted by a higher foreign exchange loss on the revaluation of other monetary assets and liabilities, higher depreciation, depletion and amortization (“DD&A”), lower long-term compensation costs due to the decrease in the Encana share price and deferred tax.

Net Loss in the first quarter of 2015 was $1,707 million compared to Net Earnings of $116 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 first quarter of 2015 was also impacted by a higher after-tax non-operating foreign exchange loss and lower after-tax unrealized hedging losses.

 

 

 

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

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Q1 Report  |  for the period ended March 31, 2015

 

 

 

Prices and Foreign Exchange Rates

 

 

		2015				2014																2013
(average for the period)		Q1				Q4				Q3				Q2				Q1				Q4				Q3				Q2
Encana Realized Pricing
Including Hedging
Natural Gas ($/Mcf)		$	4.78			$	4.16			$	4.03			$	4.08			$	5.82			$	4.34			$	4.00			$	4.17
Oil & NGLs ($/bbl)
Oil			46.17				80.38				90.22				89.55				86.34				85.39				90.42				88.27
NGLs			21.92				40.87				48.76				49.39				53.79				48.59				46.35				49.63
Total Oil & NGLs			37.83				66.40				73.50				69.53				69.19				67.01				66.95				68.25
Total ($/BOE)			31.24				35.55				35.06				30.75				39.22				31.23				28.85				29.08
Excluding Hedging
Natural Gas ($/Mcf)			3.53				3.94				3.88				4.46				6.37				3.69				3.26				3.99
Oil & NGLs ($/bbl)
Oil			40.53				66.38				90.18				92.93				86.43				82.54				96.09				85.89
NGLs			21.92				40.87				48.76				49.39				53.79				48.59				46.35				49.63
Total Oil & NGLs			34.13				57.35				73.48				71.23				69.23				65.58				69.60				67.10
Total ($/BOE)			24.82				32.25				34.36				32.93				42.12				27.63				25.23				27.99
Natural Gas Price Benchmarks
NYMEX ($/MMBtu)			2.98				4.00				4.06				4.67				4.94				3.60				3.58				4.09
AECO (C$/Mcf)			2.95				4.01				4.22				4.68				4.76				3.15				2.82				3.59
Algonquin City Gate ($/MMBtu)			11.41				4.99				2.97				4.23				20.28				7.80				3.98				4.63
Basis Differential ($/MMBtu) AECO/NYMEX			0.57				0.44				0.16				0.40				0.60				0.59				0.89				0.56
Oil Price Benchmarks
West Texas Intermediate (WTI) ($/bbl)			48.64				73.15				97.17				102.99				98.68				97.46				105.81				94.17
Edmonton Light Sweet (C$/bbl)			51.94				75.69				97.16				105.61				99.83				86.58				103.65				92.67
Foreign Exchange
Average U.S./Canadian Dollar Exchange Rate			0.806				0.881				0.918				0.917				0.906				0.953				0.963				0.977

Encana’s financial results are influenced by fluctuations in commodity prices, price differentials and the U.S./Canadian dollar exchange rate. In the first quarter of 2015, Encana’s average realized natural gas price, excluding hedging, reflected lower benchmark prices compared to 2014. Hedging activities contributed $1.25 per Mcf to Encana’s average realized natural gas price in the first quarter of 2015. The average realized natural gas price for production from Deep Panuke was $10.68 per Mcf in the first quarter of 2015 compared to $19.14 per Mcf in 2014 and increased Encana’s average realized natural gas price $0.77 per Mcf in the first quarter of 2015 compared to $1.27 per Mcf in 2014.

In the first quarter of 2015, Encana’s average realized oil and NGL prices, excluding hedging, reflected lower benchmark prices compared to 2014. Hedging activities contributed $5.64 per bbl to Encana’s average realized oil price in the first quarter 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 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.

 

 

 

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

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Q1 Report  |  for the period ended March 31, 2015

 

 

 

At March 31, 2015, Encana has hedged approximately 1,000 MMcf/d of expected April 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 55.8 Mbbls/d of expected April to December 2015 oil production using WTI fixed price contracts at an average price of $62.09 per bbl and approximately 1.2 Mbbls/d of expected 2016 oil production at an average price of $92.35 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 0.100 in the first quarter of 2015 compared to 2014. The table below summarizes selected foreign exchange impacts on Encana’s financial results in the first quarter of 2015 compared to the same period in 2014.

 

		$ millions				$/BOE
Increase (Decrease) in:
Capital Investment		$	(32	)
Transportation and Processing Expense			(24	)		$	(0.61	)
Operating Expense			(10	)			(0.26	)
Administrative Expense			(8	)			(0.20	)
Depreciation, Depletion and Amortization			(19	)			(0.49	)

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 for the first quarter of 2015. The price sensitivities below are based on business conditions, transactions and production volumes during the first 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

Increase or Decrease in:

NYMEX Natural Gas Price

+/- $

0.50/Mcf

$

45

$

33

WTI Oil Price

+/- $

10.00/bbl

55

36

 

(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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Q1 Report  |  for the period ended March 31, 2015

 

 

 

Production Volumes

 

		Three months ended March 31
(average daily, after royalties)		2015				2014
Natural Gas (MMcf/d)			1,857				2,809
Oil (Mbbls/d)			79.2				32.1
NGLs (Mbbls/d)			41.5				35.8
Total Oil & NGLs (Mbbls/d)			120.7				67.9
Total Production (MBOE/d)			430.1				536.1
Production Mix (%)
Natural Gas			72				87
Oil & NGLs			28				13

Production Volumes by Play

 

		Three months ended March 31
(average daily, after royalties)		Natural Gas (MMcf/d)								Oil & NGLs (Mbbls/d)
		2015				2014				2015				2014
Canadian Operations
Montney (1)			717				620				23.3				16.2
Duvernay			16				8				2.8				1.4
Other Upstream Operations
Wheatland (2)			111				324				1.7				11.3
Bighorn			4				246				—				12.1
Deep Panuke			182				253				—				—
Other and emerging (1)			98				117				—				—
Total Canadian Operations			1,128				1,568				27.8				41.0
USA Operations
Eagle Ford			36				—				36.0				—
Permian			34				—				26.7				—
DJ Basin			49				40				14.3				10.5
San Juan			13				7				6.7				2.7
Other Upstream Operations
Piceance			343				436				3.7				5.4
Haynesville			230				331				—				—
Jonah			—				282				—				4.7
East Texas			—				113				—				1.2
Other and emerging			24				32				5.5				2.4
Total USA Operations			729				1,241				92.9				26.9
Total Production Volumes			1,857				2,809				120.7				67.9
Total Production Volumes – Growth Assets (1)			865				675				114.1				31.5

 

(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.

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 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.

 

 

 

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

---

Q1 Report  |  for the period ended March 31, 2015

 

 

 

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

Three months ended March 31, 2015 versus March 31, 2014

In the first quarter of 2015, average natural gas production volumes of 1,857 MMcf/d decreased 952 MMcf/d from 2014. The USA Operations volumes were lower in the first quarter 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 first quarter 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 a production decline at Deep Panuke primarily due to a higher water production rate, partially offset by a successful drilling program in Montney.

In the first quarter of 2015, average oil and NGL production volumes of 120.7 Mbbls/d increased 52.8 Mbbls/d from 2014. The USA Operations volumes were higher in the first quarter 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 San Juan, the DJ Basin and the TMS, 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 first quarter 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 a successful drilling program in Montney.

 

 

 

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

---

Q1 Report  |  for the period ended March 31, 2015

 

 

 

Net Capital Investment

 

		Three months ended March 31
($ millions)		2015				2014
Canadian Operations		$	151			$	281
USA Operations			583				226
Market Optimization			—				1
Corporate & Other			2				3
Capital Investment			736				511
Acquisitions			35				23
Divestitures			(873	)			(47	)
Net Acquisitions & (Divestitures)			(838	)			(24	)
Net Capital Investment		$	(102	)		$	487

Capital Investment by Play

 

		Three months ended March 31
($ millions)		2015				2014
Canadian Operations
Montney (1)		$	79			$	208
Duvernay			70				71
Other Upstream Operations
Wheatland (2)			—				18
Bighorn			—				9
Deep Panuke			2				(3	)
Other and emerging (1)			—				(22	)
Total Canadian Operations		$	151			$	281
USA Operations
Eagle Ford		$	197			$	—
Permian			217				—
DJ Basin			88				59
San Juan			36				52
Other Upstream Operations
Piceance			3				21
Haynesville			2				38
Jonah			—				11
East Texas			—				10
Other and emerging			40				35
Total USA Operations		$	583			$	226
Capital Investment – Growth Assets (1)		$	713			$	410

 

(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 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 first quarter of 2015, capital investment in the TMS was $26 million (2014 – $20 million).

 

 

 

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

---

Q1 Report  |  for the period ended March 31, 2015

 

 

 

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

Three months ended March 31, 2015 versus March 31, 2014

Capital investment during the first quarter of 2015 was $736 million compared to $511 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 quarter of 2015, capital spending in the Company’s growth assets totaled $713 million (2014 – $410 million), representing approximately 97 percent (2014 – 80 percent) of the Company’s capital investment, with $563 million (2014 – $279 million) spent on Encana’s top four strategic assets.

Divestitures

Divestitures in the first quarter of 2015 were $829 million in the Canadian Operations. This 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. Encana retains a working interest in approximately 1.1 million net acres in the area. The Canadian Operations also included approximately C$455 million ($359 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 CRP. Further information can be found in Note 15 to the Interim Condensed Consolidated Financial Statements.

Amounts received from the divestiture transactions above have been deducted from the Canadian full cost pool.

2014 Capital Transactions

The following significant acquisition and divestiture transactions, which occurred during 2014, have impacted the Company’s production volume and operating cash flow variances for the first quarter of 2015:

 

Transaction		Location				Closing Date
Canadian Operations
Divestiture of Encana’s investment in PrairieSky (1)			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.

Refer to the annual MD&A for the year ended December 31, 2014 for a comprehensive discussion of these transactions.

 

 

 

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

---

Q1 Report  |  for the period ended March 31, 2015

 

 

 

Results of Operations

Canadian Operations

 

Operating Cash Flow

 

		Three months ended March 31
		Natural Gas								Oil & NGLs								Total (1)
($ millions)		2015				2014				2015				2014				2015				2014
Revenues, Net of Royalties, excluding Hedging		$	396			$	1,017			$	77			$	245			$	476			$	1,268
Realized Financial Hedging Gain (Loss)			154				(75	)			2				—				156				(75	)
Revenues, Net of Royalties			550				942				79				245				632				1,193
Expenses
Production and mineral taxes			—				2				—				3				—				5
Transportation and processing			163				201				14				14				177				215
Operating			36				84				6				6				42				92
Operating Cash Flow		$	351			$	655			$	59			$	222			$	413			$	881
Production Volumes
		Three months ended March 31
		Natural Gas								Oil & NGLs								Total
		(MMcf/d)								(Mbbls/d)								(MBOE/d)
		2015				2014				2015				2014				2015				2014
Production Volumes – After Royalties			1,128				1,568				27.8				41.0				215.8				302.4
Operating Netback (2)
		Three months ended March 31
		Natural Gas								Oil & NGLs								Total
		($/Mcf)								($/bbl)								($/BOE)
		2015				2014				2015				2014				2015				2014
Revenues, Net of Royalties, excluding Hedging		$	3.89			$	7.17			$	30.65			$	66.36			$	24.30			$	46.20
Realized Financial Hedging Gain (Loss)			1.52				(0.53	)			0.78				(0.09	)			8.04				(2.77	)
Revenues, Net of Royalties			5.41				6.64				31.43				66.27				32.34				43.43
Expenses
Production and mineral taxes			—				0.01				0.04				0.80				0.02				0.18
Transportation and processing			1.60				1.42				5.82				3.80				9.12				7.87
Operating			0.35				0.59				2.31				1.75				2.14				3.29
Operating Netback		$	3.46			$	4.62			$	23.26			$	59.92			$	21.06			$	32.09

 

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

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

Three months ended March 31, 2015 versus March 31, 2014

Operating Cash Flow of $413 million decreased $468 million primarily due to the following significant items:

 

•

Lower natural gas prices reflected lower benchmark prices, which decreased revenues $333 million. The average realized natural gas price for production from Deep Panuke was $10.68 per Mcf compared to $19.14 per Mcf in 2014 and increased the average realized natural gas price $1.30 per Mcf compared to $2.29 per Mcf in 2014.

 

•

Lower liquids prices reflected lower benchmark prices, which decreased revenues $89 million.

 

 

 

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

---

Q1 Report  |  for the period ended March 31, 2015

 

 

 

•

Average natural gas production volumes of 1,128 MMcf/d were lower by 440 MMcf/d, which decreased revenues $288 million. Average oil and NGL production volumes of 27.8 Mbbls/d were lower by 13.2 Mbbls/d, which decreased revenues $79 million. Changes in production volumes are discussed in the Production Volumes section of this MD&A.

 

•

Realized financial hedging gains were $156 million compared to losses of $75 million in 2014.

 

•

Transportation and processing expense decreased $38 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 the sale of certain assets included in Wheatland in January 2015, partially offset by higher liquids volumes processed in Montney.

 

•

Operating expense decreased $50 million primarily due to the sale of certain assets included in Wheatland in January 2015, lower long-term compensation costs due to the decrease in the Encana share price, the lower U.S./Canadian dollar exchange rate, and the sale of the Bighorn assets in the third quarter of 2014.

Other Expenses

 

		Three months ended March 31
($ millions, except as indicated)		2015				2014
Depreciation, depletion & amortization		$	105			$	172
Depletion rate ($/BOE)			5.39				6.28

DD&A decreased primarily due to lower production volumes and the lower U.S./Canadian dollar exchange rate. The lower depletion rate in the first quarter of 2015 resulted primarily from 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$

---

Q1 Report  |  for the period ended March 31, 2015

 

 

 

USA Operations

 

Operating Cash Flow

 

		Three months ended March 31
		Natural Gas								Oil & NGLs								Total (1)
($ millions)		2015				2014				2015				2014				2015				2014
Revenues, Net of Royalties, excluding Hedging		$	195			$	596			$	295			$	179			$	496			$	778
Realized Financial Hedging Gain (Loss)			54				(65	)			38				—				92				(65	)
Revenues, Net of Royalties			249				531				333				179				588				713
Expenses
Production and mineral taxes			4				29				15				13				19				42
Transportation and processing			151				163				4				—				155				163
Operating			49				68				75				8				125				74
Operating Cash Flow		$	45			$	271			$	239			$	158			$	289			$	434
Production Volumes
		Three months ended March 31
		Natural Gas								Oil & NGLs								Total
		(MMcf/d)								(Mbbls/d)								(MBOE/d)
		2015				2014				2015				2014				2015				2014
Production Volumes – After Royalties			729				1,241				92.9				26.9				214.3				233.7
Operating Netback (2)
		Three months ended March 31
		Natural Gas								Oil & NGLs								Total
		($/Mcf)								($/bbl)								($/BOE)
		2015				2014				2015				2014				2015				2014
Revenues, Net of Royalties, excluding Hedging		$	2.97			$	5.34			$	35.18			$	73.61			$	25.34			$	36.82
Realized Financial Hedging Gain (Loss)			0.82				(0.58	)			4.58				0.04				4.78				(3.07	)
Revenues, Net of Royalties			3.79				4.76				39.76				73.65				30.12				33.75
Expenses
Production and mineral taxes			0.06				0.26				1.80				5.46				0.97				1.99
Transportation and processing			2.30				1.46				0.43				—				8.02				7.75
Operating			0.75				0.61				8.96				3.16				6.44				3.60
Operating Netback		$	0.68			$	2.43			$	28.57			$	65.03			$	14.69			$	20.41

 

(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.

Three months ended March 31, 2015 versus 2014

Operating Cash Flow of $289 million decreased $145 million primarily due to the following significant items:

 

•

Lower natural gas prices reflected lower benchmark prices, which decreased revenues $139 million. Lower liquids prices reflected lower benchmark prices, which decreased revenues $119 million.

 

•

Average natural gas production volumes of 729 MMcf/d were lower by 512 MMcf/d, which decreased revenues $262 million. Average oil and NGL production volumes of 92.9 Mbbls/d were higher by 66.0 Mbbls/d, which increased revenues $235 million. Changes in production volumes are discussed in the Production Volumes section of this MD&A.

 

•

Realized financial hedging gains were $92 million compared to losses of $65 million in 2014.

 

 

 

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

---

Q1 Report  |  for the period ended March 31, 2015

 

 

 

•

Production and mineral taxes decreased $23 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.

 

•

Operating expense increased $51 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 March 31
($ millions, except as indicated)		2015				2014
Depreciation, depletion & amortization		$	336			$	212
Depletion rate ($/BOE)			16.96				10.09
Impairments			1,916				—

DD&A increased primarily due to a higher depletion rate of $16.96 per BOE in 2015 compared to $10.09 per BOE in 2014, partially offset by lower production volumes. The higher depletion rate in the first quarter of 2015 resulted primarily from the acquisitions of Eagle Ford and the Permian assets in the second and fourth quarters of 2014, respectively, and a decrease in proved reserves as a result of the sale of the Jonah properties in the second quarter of 2014.

In the first quarter of 2015, the USA Operations recognized a before-tax non-cash ceiling test impairment of $1,916 million. The impairment 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)
March 31, 2015			3.88				82.72
December 31, 2014			4.34				94.99
March 31, 2014			3.99				98.46

 

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

 

 

 

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

---

Q1 Report  |  for the period ended March 31, 2015

 

 

 

Market Optimization

 

 

		Three months ended March 31
($ millions)		2015				2014
Revenues		$	139			$	244
Expenses
Operating			16				13
Purchased product			121				228
Depreciation, depletion and amortization			—				3
		$	2			$	—

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 first quarter 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 March 31
($ millions)		2015				2014
Revenues		$	(110	)		$	(258	)
Expenses
Transportation and processing			8				1
Operating			6				10
Depreciation, depletion and amortization			25				31
		$	(149	)		$	(300	)

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$

---

Q1 Report  |  for the period ended March 31, 2015

 

 

 

Other Operating Results

Expenses

 

 

		Three months ended March 31
($ millions)		2015				2014
Accretion of asset retirement obligation		$	12			$	13
Administrative			72				102
Interest			125				147
Foreign exchange (gain) loss, net			656				224
(Gain) loss on divestitures			(14	)			1
Other			1				—
		$	852			$	487

Administrative expense in the first quarter of 2015 decreased from 2014 primarily due to lower long-term compensation costs due to the decrease in the Encana share price, lower restructuring costs and the lower U.S./Canadian dollar exchange rate. There were no restructuring costs incurred in the first quarter of 2015 compared to $15 million in 2014.

Interest expense in the first quarter of 2015 decreased from 2014 primarily due to lower interest on debt resulting from the long-term debt repayment and redemption in the first half of 2014.

Foreign exchange gains and losses result from the impact of the fluctuations in the Canadian to U.S. dollar exchange rate. Foreign exchange losses increased in the first quarter of 2015 primarily due to higher losses on the translation of U.S. dollar long-term debt issued from Canada, intercompany transactions and the revaluation and settlement of other monetary assets and liabilities.

Gain on divestitures in the first quarter of 2015 primarily includes a gain on the sale of the Encana Place office building in Calgary.

Income Tax

 

 

		Three months ended March 31
($ millions)		2015				2014
Current Income Tax		$	16			$	16
Deferred Income Tax (Recovery)			(963	)			12
Income Tax Expense (Recovery)		$	(947	)		$	28

Total income tax recovery in the first quarter 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 and amounts in respect of prior periods. The Company’s effective tax rate for the first quarter of 2015 is higher than 2014 primarily as a result of changes in expected annual earnings. 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.

 

 

 

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

---

Q1 Report  |  for the period ended March 31, 2015

 

 

 

Liquidity and Capital Resources

 

		Three months ended March 31
($ millions)		2015				2014
Net Cash From (Used In)
Operating activities		$	482			$	943
Investing activities			268				(446	)
Financing activities			968				(845	)
Foreign exchange gain (loss) on cash and cash equivalents held in foreign currency			(26	)			(56	)
Increase (Decrease) in Cash and Cash Equivalents		$	1,692			$	(404	)
Cash and Cash Equivalents, End of Period		$	2,030			$	2,162

Operating Activities

 

Net cash from operating activities in the first quarter of 2015 of $482 million decreased $461 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 quarter of 2015, the net change in non-cash working capital was a deficit of $6 million compared to $142 million in 2014.

The Company had a working capital surplus of $748 million at March 31, 2015 compared to $455 million at December 31, 2014. The increase in working capital is primarily due to an increase in cash and cash equivalents and a decrease in accounts payable and accrued liabilities, partially offset by an increase in the current portion of long-term debt, a decrease in accounts receivable and accrued revenues and a decrease in income tax receivable. At March 31, 2015, working capital included cash and cash equivalents of $2,030 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 from investing activities in the first quarter of 2015 was $268 million compared to net cash used of $446 million in 2014. The change was primarily due to higher proceeds from divestitures, partially offset by higher capital expenditures. Further information on capital expenditures and acquisitions and divestitures can be found in the Net Capital Investment section of this MD&A.

Financing Activities

 

Net cash from financing activities in the first quarter of 2015 was $968 million compared to net cash used of $845 million in 2014. The change was primarily due to proceeds from the issuance of common shares pursuant to the Share Offering in the first quarter of 2015 and the repayment of long-term debt in the first quarter of 2014.

Long-Term Debt

Encana’s long-term debt, excluding the current portion, totaled $5,925 million at March 31, 2015 and $7,340 million at December 31, 2014. The current portion of long-term debt outstanding was $1,291 million at March 31, 2015. This amount was classified as current as a result of the Company’s planned debt redemption in April 2015, as discussed below. There was no current portion of long-term debt outstanding at December 31, 2014.

On April 6, 2015, the Company used the net proceeds from the Share Offering and cash on hand to complete the redemption of its $700 million 5.90 percent notes due December 1, 2017 and its C$750 million 5.80 percent medium-term notes due January 18, 2018. The note redemptions required an aggregate one-time early interest payment of approximately $165 million and is expected to save Encana a gross amount of approximately $205 million in future interest expense, based on current foreign exchange and treasury rates.

 

 

 

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

---

Q1 Report  |  for the period ended March 31, 2015

 

 

 

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 March 31, 2015, Encana had an outstanding balance of $1,211 million which reflected U.S. CP issuances that had an average term of 38 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. Additional detail on Encana’s credit facilities can be found below.

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.

Credit Facilities and Shelf Prospectus

Encana maintains two revolving bank credit facilities which remain committed through June 2018. At March 31, 2015, Encana had available unused committed revolving bank credit facilities of $2.6 billion as follows:

 

•

A committed revolving bank credit facility for C$3.5 billion ($2.8 billion) for Encana, of which $1.6 billion remained unused.

 

•

A committed revolving bank credit facility for a U.S. subsidiary for $1.0 billion, all of which remained unused.

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 March 31, 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.

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 29 percent at March 31, 2015 and 30 percent at December 31, 2014.

Outstanding Share Data

 

(millions)		December 31, 2014				March 31, 2015				May 8, 2015
Common Shares Outstanding			741.2				840.9				840.9
Stock Options with TSARs attached:
Outstanding			21.3				20.8				20.6
Exercisable			10.0				11.2				11.1

Pursuant to the Share Offering, Encana issued approximately 98.4 million common shares during the first quarter of 2015.

 

 

 

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

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Q1 Report  |  for the period ended March 31, 2015

 

 

 

During the first quarter of 2015, Encana issued 1,267,680 common shares under the Company’s dividend reinvestment plan (“DRIP”) compared with 54,472 common shares in 2014. The number of common shares issued under the DRIP increased in the first quarter of 2015 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.

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.

Dividends

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

 

		As at March 31
($ millions, except as indicated)		2015				2014
Dividend Payments		$	52			$	52
Dividend Payments ($/share)		$	0.07			$	0.07

The dividends paid in the first quarter of 2015 included $14 million in common shares issued in lieu of cash dividends under the DRIP compared to $1 million 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 May 11, 2015, the Board declared a dividend of $0.07 per share payable on June 30, 2015 to common shareholders of record as of June 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.

 

		March 31, 2015				December 31, 2014
Debt to Debt Adjusted Cash Flow			2.6x				2.1x
Debt to Adjusted Capitalization			29	%			30	%

Subsequent to the debt redemption completed on April 6, 2015, Debt to Debt Adjusted Cash Flow was approximately 2.1x and Debt to Adjusted Capitalization was approximately 26 percent.

 

 

 

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

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Q1 Report  |  for the period ended March 31, 2015

 

 

 

Commitments and Contingencies

Commitments

The following table outlines the Company’s commitments at March 31, 2015:

 

		Expected Future Payments
($ millions, undiscounted)		2015				2016				2017				2018				2019				Thereafter				Total
Transportation and Processing		$	598			$	787			$	779			$	798			$	674			$	3,085			$	6,721
Drilling and Field Services			164				128				90				47				14				16				459
Operating Leases			24				27				22				21				8				20				122
Commitments		$	786			$	942			$	891			$	866			$	696			$	3,121			$	7,302

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 15 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 20 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$

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Q1 Report  |  for the period ended March 31, 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 March 31, 2015, is disclosed in Note 20 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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Q1 Report  |  for the period ended March 31, 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.

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.

 

 

 

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

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Q1 Report  |  for the period ended March 31, 2015

 

 

 

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.

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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Q1 Report  |  for the period ended March 31, 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.

Except for changes relating to the continuing integration of Athlon Energy Inc. (“Athlon”), as discussed below, there have been no changes in the Company’s internal control over financial reporting during the three months ended March 31, 2015 that have materially affected, or are reasonably likely to materially affect, the effectiveness of the internal control over financial reporting.

In accordance with Section 3.3(1) of National Instrument 52-109 and Rules 13a-15(f) and 15d-15(f) under the United States Securities and Exchange Act of 1934, as amended, Management has limited the scope and design and subsequent evaluation of internal controls over financial reporting to exclude the controls, policies and procedures of Athlon, acquired through a business combination on November 13, 2014. Summary financial information related to Athlon’s operations included in Encana’s Interim Condensed Consolidated Financial Statements for the period ended March 31, 2015 is as follows:

 

($ millions)
Revenues		$	55
Net Earnings			25
Current Assets			61
Non-Current Assets			3,059
Current Liabilities			41
Non-Current Liabilities			168

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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Q1 Report  |  for the period ended March 31, 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 March 31, 2015, $43 million of debt issuance costs were presented in Other Assets on the Company’s interim Condensed Consolidated Balance Sheet ($48 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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Q1 Report  |  for the period ended March 31, 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; 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.

 

		2015				2014																2013
($ millions)		Q1				Q4				Q3				Q2				Q1				Q4				Q3				Q2
Cash From (Used in) Operating Activities		$	482			$	261			$	696			$	767			$	943			$	462			$	935			$	554
(Add back) deduct:
Net change in other assets and liabilities			(7	)			(15	)			(11	)			(8	)			(9	)			(21	)			(15	)			(22	)
Net change in non-cash working capital			(6	)			(141	)			155				119				(142	)			(183	)			300				(81	)
Cash tax on sale of assets			—				40				(255	)			—				—				(11	)			(10	)			(8	)
Cash Flow		$	495			$	377			$	807			$	656			$	1,094			$	677			$	660			$	665
Deduct:
Capital investment			736				857				598				560				511				717				641				639
Free Cash Flow		$	(241	)		$	(480	)		$	209			$	96			$	583			$	(40	)		$	19			$	26

 

 

 

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

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Q1 Report  |  for the period ended March 31, 2015

 

 

 

Operating Earnings

 

Operating Earnings 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 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 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.

 

		2015				2014																2013
($ millions)		Q1				Q4				Q3				Q2				Q1				Q4				Q3				Q2
Net Earnings (Loss) Attributable to Common Shareholders		$	(1,707	)		$	198			$	2,807			$	271			$	116			$	(251	)		$	188			$	730
After-tax (addition) / deduction:
Unrealized hedging gain (loss)			(98	)			341				160				8				(203	)			(209	)			(89	)			332
Impairments			(1,222	)			—				—				—				—				—				(16	)			—
Restructuring charges			—				(4	)			(5	)			(5	)			(10	)			(64	)			—				—
Non-operating foreign exchange gain (loss)			(508	)			(151	)			(218	)			156				(194	)			(124	)			105				(162	)
Gain (loss) on divestitures			10				(11	)			2,399				135				—				—				—				—
Income tax adjustments			102				(12	)			190				(194	)			8				(80	)			38				313
Operating Earnings		$	9			$	35			$	281			$	171			$	515			$	226			$	150			$	247

 

 

 

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

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Q1 Report  |  for the period ended March 31, 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.

 

		2015				2014																2013
($ millions)		Q1				Q4				Q3				Q2				Q1				Q4				Q3				Q2
Upstream Operating Cash Flow
Canadian Operations		$	413			$	341			$	477			$	447			$	881			$	526			$	406			$	383
USA Operations			289				480				505				353				434				375				388				405
		$	702			$	821			$	982			$	800			$	1,315			$	901			$	794			$	788
(Add back) deduct:
Realized Hedging Gain (Loss)
Canadian Operations		$	156			$	49			$	19			$	(49	)		$	(75	)		$	90			$	95			$	21
USA Operations			92				78				11				(49	)			(65	)			83				77				30
		$	248			$	127			$	30			$	(98	)		$	(140	)		$	173			$	172			$	51
Upstream Operating Cash Flow, excluding Hedging
Canadian Operations		$	257			$	292			$	458			$	496			$	956			$	436			$	311			$	362
USA Operations			197				402				494				402				499				292				311				375
		$	454			$	694			$	952			$	898			$	1,455			$	728			$	622			$	737

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$

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Q1 Report  |  for the period ended March 31, 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)		March 31, 2015				December 31, 2014
Debt		$	7,216			$	7,340
Cash Flow			2,335				2,934
Interest Expense, after tax			470				486
Debt Adjusted Cash Flow		$	2,805			$	3,420
Debt to Debt Adjusted Cash Flow			2.6x				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)		March 31, 2015				December 31, 2014
Debt		$	7,216			$	7,340
Total Shareholders’ Equity			9,517				9,685
Equity Adjustment for Impairments at December 31, 2011			7,746				7,746
Adjusted Capitalization		$	24,479			$	24,771
Debt to Adjusted Capitalization			29	%			30	%

 

 

 

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

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Q1 Report  |  for the period ended March 31, 2015

 

 

 

Advisory

Forward-Looking Statements

 

In the interest of providing Encana shareholders and potential investors with information regarding the Company and its subsidiaries, including Management’s assessment of Encana’s and its subsidiaries’ future plans and operations, certain statements contained in this document constitute forward-looking statements or information (collectively referred to herein as “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. Forward-looking statements in this document include, but are not limited to, statements with respect to:

 

 

 

 

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

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Q1 Report  |  for the period ended March 31, 2015

 

 

 

Readers are cautioned not to place undue reliance 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, forward-looking statements involve numerous assumptions, known and unknown risks and uncertainties, both general and specific, that contribute to the possibility that the predictions, forecasts, projections and other forward-looking statements will not occur, which may cause the Company’s actual performance and financial results in future periods to differ materially from any estimates or projections of future performance or results expressed or implied by such forward-looking statements. These assumptions, risks and uncertainties include, among other things:

 

 

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 foregoing list of important factors is not exhaustive. Furthermore, the forward-looking statements contained in this document are made as of the date hereof 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 this cautionary statement.

Forward-looking information respecting anticipated 2015 cash flow for Encana is based upon, among other things, achieving average production for 2015 of between 1,600 MMcf/d and 1,700 MMcf/d of natural gas and 130 Mbbls/d to 150 Mbbls/d of liquids, commodity prices for natural gas and liquids based on NYMEX $3.00 per MMBtu and WTI of $50 per bbl, an estimated U.S./Canadian dollar exchange rate of 0.80 and a weighted average number of outstanding shares for Encana of approximately 821 million.

 

 

 

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

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Q1 Report  |  for the period ended March 31, 2015

 

 

 

Assumptions relating to forward-looking statements generally include Encana’s current expectations and projections made in light of, and generally consistent with, its historical experience and its perception of historical trends.

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 May 12, 2015, which is available on Encana’s website at www.encana.com, on SEDAR at www.sedar.com and EDGAR at www.sec.gov.

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 are anticipated to come 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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Q1 Report  |  for the period ended March 31, 2015

 

 

 

Condensed Consolidated Statement of Earnings (unaudited)

 

 

						Three Months Ended March 31,
($ millions, except per share amounts)						2015				2014
Revenues, Net of Royalties			(Note 3)			$	1,249			$	1,892
Expenses			(Note 3)
Production and mineral taxes							19				47
Transportation and processing							340				379
Operating							189				189
Purchased product							121				228
Depreciation, depletion and amortization							466				418
Impairments			(Note 9)				1,916				—
Accretion of asset retirement obligation			(Note 12)				12				13
Administrative			(Note 16)				72				102
Interest			(Note 6)				125				147
Foreign exchange (gain) loss, net			(Note 7)				656				224
(Gain) loss on divestitures			(Note 5)				(14	)			1
Other							1				—
							3,903				1,748
Net Earnings (Loss) Before Income Tax							(2,654	)			144
Income tax expense (recovery)			(Note 8)				(947	)			28
Net Earnings (Loss)						$	(1,707	)		$	116
Net Earnings (Loss) per Common Share
Basic & Diluted			(Note 13)			$	(2.25	)		$	0.16

Condensed Consolidated Statement of Comprehensive Income (unaudited)

 

 

						Three Months Ended March 31,
($ millions)						2015				2014
Net Earnings (Loss)						$	(1,707	)		$	116
Other Comprehensive Income, Net of Tax
Foreign currency translation adjustment			(Note 14)				478				24
Pension and other post-employment benefit plans			(Notes 14, 18)				1				—
Other Comprehensive Income							479				24
Comprehensive Income (Loss)						$	(1,228	)		$	140

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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Q1 Report  |  for the period ended March 31, 2015

 

 

 

Condensed Consolidated Balance Sheet (unaudited)

 

 

($ millions)						As at March 31, 2015				As at December 31, 2014
Assets
Current Assets
Cash and cash equivalents						$	2,030			$	338
Accounts receivable and accrued revenues							940				1,307
Risk management			(Note 20)				607				707
Income tax receivable							384				509
Deferred income taxes							101				—
							4,062				2,861
Property, Plant and Equipment, at cost:			(Note 9)
Natural gas and oil properties, based on full cost accounting
Proved properties							41,086				42,615
Unproved properties							5,984				6,133
Other							2,446				2,711
Property, plant and equipment							49,516				51,459
Less: Accumulated depreciation, depletion and amortization							(34,354	)			(33,444	)
Property, plant and equipment, net			(Note 3)				15,162				18,015
Cash in Reserve							44				73
Other Assets							356				394
Risk Management			(Note 20)				13				65
Deferred Income Taxes							349				296
Goodwill			(Notes 3, 4)				2,850				2,917
			(Note 3)			$	22,836			$	24,621
Liabilities and Shareholders’ Equity
Current Liabilities
Accounts payable and accrued liabilities						$	1,903			$	2,243
Income tax payable							16				15
Risk management			(Note 20)				13				20
Current portion of long-term debt			(Note 10)				1,291				—
Deferred income taxes							91				128
							3,314				2,406
Long-Term Debt			(Note 10)				5,925				7,340
Other Liabilities and Provisions			(Note 11)				2,225				2,484
Risk Management			(Note 20)				12				7
Asset Retirement Obligation			(Note 12)				773				870
Deferred Income Taxes							1,070				1,829
							13,319				14,936
Commitments and Contingencies			(Note 21)
Shareholders’ Equity
Share capital - authorized unlimited common shares, without par value 2015 issued and outstanding: 840.9 million shares (2014: 741.2 million shares)			(Note 13)				3,562				2,450
Paid in surplus			(Note 17)				1,358				1,358
Retained earnings							3,429				5,188
Accumulated other comprehensive income			(Note 14)				1,168				689
Total Shareholders’ Equity							9,517				9,685
						$	22,836			$	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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Q1 Report  |  for the period ended March 31, 2015

 

 

 

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

 

 

Three Months Ended March 31, 2015 ($ millions)						Share Capital				Paid in Surplus				Retained Earnings				Accumulated Other Comprehensive Income				Total Shareholders’ Equity
Balance, December 31, 2014						$	2,450			$	1,358			$	5,188			$	689			$	9,685
Net Earnings (Loss)							—				—				(1,707	)			—				(1,707	)
Dividends on Common Shares			(Note 13)				—				—				(52	)			—				(52	)
Common Shares Issued			(Note 13)				1,098				—				—				—				1,098
Common Shares Issued Under Dividend Reinvestment Plan			(Note 13)				14				—				—				—				14
Other Comprehensive Income			(Note 14)				—				—				—				479				479
Balance, March 31, 2015						$	3,562			$	1,358			$	3,429			$	1,168			$	9,517
Three Months Ended March 31, 2014 ($ millions)						Share Capital				Paid in Surplus				Retained Earnings				Accumulated Other Comprehensive Income				Total Shareholders’ Equity
Balance, December 31, 2013						$	2,445			$	15			$	2,003			$	684			$	5,147
Share-Based Compensation			(Note 17)				—				(2	)			—				—				(2	)
Net Earnings							—				—				116				—				116
Dividends on Common Shares			(Note 13)				—				—				(52	)			—				(52	)
Common Shares Issued Under Dividend Reinvestment Plan			(Note 13)				1				—				—				—				1
Other Comprehensive Income			(Note 14)				—				—				—				24				24
Balance, March 31, 2014						$	2,446			$	13			$	2,067			$	708			$	5,234

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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Q1 Report  |  for the period ended March 31, 2015

 

 

 

Condensed Consolidated Statement of Cash Flows (unaudited)

 

 

						Three Months Ended March 31,
($ millions)						2015				2014
Operating Activities
Net earnings (loss)						$	(1,707	)		$	116
Depreciation, depletion and amortization							466				418
Impairments			(Note 9)				1,916				—
Accretion of asset retirement obligation			(Note 12)				12				13
Deferred income taxes			(Note 8)				(963	)			12
Unrealized (gain) loss on risk management			(Note 20)				136				285
Unrealized foreign exchange (gain) loss			(Note 7)				559				197
(Gain) loss on divestitures			(Note 5)				(14	)			1
Other							90				52
Net change in other assets and liabilities							(7	)			(9	)
Net change in non-cash working capital							(6	)			(142	)
Cash From (Used in) Operating Activities							482				943
Investing Activities
Capital expenditures			(Note 3)				(736	)			(511	)
Acquisitions			(Note 5)				(35	)			(23	)
Proceeds from divestitures			(Note 5)				873				47
Cash in reserve							29				3
Net change in investments and other							137				38
Cash From (Used in) Investing Activities							268				(446	)
Financing Activities
Net issuance (repayment) of revolving long-term debt							(66	)			—
Repayment of long-term debt			(Note 10)				—				(770	)
Issuance of common shares			(Note 13)				1,088				—
Dividends on common shares			(Note 13)				(38	)			(51	)
Capital lease payments and other financing arrangements			(Note 11)				(16	)			(24	)
Cash From (Used in) Financing Activities							968				(845	)
Foreign Exchange Gain (Loss) on Cash and Cash Equivalents Held in Foreign Currency							(26	)			(56	)
Increase (Decrease) in Cash and Cash Equivalents							1,692				(404	)
Cash and Cash Equivalents, Beginning of Period							338				2,566
Cash and Cash Equivalents, End of Period						$	2,030			$	2,162
Cash, End of Period						$	202			$	208
Cash Equivalents, End of Period							1,828				1,954
Cash and Cash Equivalents, End of Period						$	2,030			$	2,162

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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Q1 Report  |  for the period ended March 31, 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. 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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Q1 Report  |  for the period ended March 31, 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 March 31, 2015, $43 million of debt issuance costs were presented in Other Assets on the Company’s interim Condensed Consolidated Balance Sheet ($48 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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Q1 Report  |  for the period ended March 31, 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 March 31)

Segment and Geographic Information

 

		Canadian Operations								USA Operations								Market Optimization
		2015				2014				2015				2014				2015				2014
Revenues, Net of Royalties		$	632			$	1,193			$	588			$	713			$	139			$	244
Expenses
Production and mineral taxes			—				5				19				42				—				—
Transportation and processing			177				215				155				163				—				—
Operating			42				92				125				74				16				13
Purchased product			—				—				—				—				121				228
			413				881				289				434				2				3
Depreciation, depletion and amortization			105				172				336				212				—				3
Impairments			—				—				1,916				—				—				—
		$	308			$	709			$	(1,963	)		$	222			$	2			$	—

 

		Corporate & Other								Consolidated
		2015				2014				2015				2014
Revenues, Net of Royalties		$	(110	)		$	(258	)		$	1,249			$	1,892
Expenses
Production and mineral taxes			—				—				19				47
Transportation and processing			8				1				340				379
Operating			6				10				189				189
Purchased product			—				—				121				228
			(124	)			(269	)			580				1,049
Depreciation, depletion and amortization			25				31				466				418
Impairments			—				—				1,916				—
		$	(149	)		$	(300	)			(1,802	)			631
Accretion of asset retirement obligation											12				13
Administrative											72				102
Interest											125				147
Foreign exchange (gain) loss, net											656				224
(Gain) loss on divestitures											(14	)			1
Other											1				—
											852				487
Net Earnings (Loss) Before Income Tax											(2,654	)			144
Income tax expense (recovery)											(947	)			28
Net Earnings (Loss)										$	(1,707	)		$	116

Intersegment Information

 

		Market Optimization
		Marketing Sales								Upstream Eliminations								Total
		2015				2014				2015				2014				2015				2014
Revenues, Net of Royalties		$	1,165			$	2,227			$	(1,026	)		$	(1,983	)		$	139			$	244
Expenses
Transportation and processing			95				127				(95	)			(127	)			—				—
Operating			16				25				—				(12	)			16				13
Purchased product			1,052				2,070				(931	)			(1,842	)			121				228
Operating Cash Flow		$	2			$	5			$	—			$	(2	)		$	2			$	3

 

 

 

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

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Q1 Report  |  for the period ended March 31, 2015

 

 

 

Notes to Condensed Consolidated Financial Statements (unaudited)

 

(All amounts in $ millions unless otherwise specified)

 

3.	Segmented Information (continued)

 

Capital Expenditures

 

		Three Months Ended March 31,
		2015				2014
Canadian Operations		$	151			$	281
USA Operations			583				226
Market Optimization			—				1
Corporate & Other			2				3
		$	736			$	511

Goodwill, Property, Plant and Equipment and Total Assets by Segment

 

		Goodwill								Property, Plant and Equipment								Total Assets
		As at								As at								As at
		March 31, 2015				December 31, 2014				March 31, 2015				December 31, 2014				March 31, 2015				December 31, 2014
Canadian Operations		$	721			$	788			$	1,304			$	2,338			$	2,447			$	3,632
USA Operations			2,129				2,129				12,166				13,817				14,779				16,800
Market Optimization			—				—				1				1				73				181
Corporate & Other			—				—				1,691				1,859				5,537				4,008
		$	2,850			$	2,917			$	15,162			$	18,015			$	22,836			$	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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Q1 Report  |  for the period ended March 31, 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 quarter 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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Q1 Report  |  for the period ended March 31, 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 three months ended March 31, 2015 include the results from Eagle Ford and Athlon.

 

Three Months Ended March 31, 2014 ($ millions, except per share amounts)		Eagle Ford				Athlon
Revenues, Net of Royalties		$	2,276			$	1,987
Net Earnings		$	268			$	118
Net Earnings per Common Share Basic & Diluted		$	0.36			$	0.16

 

5.	Acquisitions and Divestitures

 

		Three Months Ended March 31,
		2015				2014
Acquisitions
Canadian Operations		$	—			$	2
USA Operations			1				21
Corporate & Other			34				—
Total Acquisitions			35				23
Divestitures
Canadian Operations			(829	)			(32	)
USA Operations			3				(14	)
Corporate & Other			(47	)			(1	)
Total Divestitures			(873	)			(47	)
Net Acquisitions & (Divestitures)		$	(838	)		$	(24	)

Divestitures

For the three months ended March 31, 2015, divestitures in the Canadian Operations were $829 million (2014 - $32 million), which primarily included the sale of certain assets in Wheatland located in central and southern Alberta for proceeds of approximately C$558 million ($468 million), after closing adjustments and the sale of certain natural gas gathering and compression assets in the Montney area of northeastern British Columbia for proceeds of approximately C$455 million ($359 million) after closing adjustments. Amounts received from the divestiture transactions have been deducted from the Canadian full cost pool.

Corporate and Other acquisitions and divestitures include 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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Q1 Report  |  for the period ended March 31, 2015

 

 

 

Notes to Condensed Consolidated Financial Statements (unaudited)

 

(All amounts in $ millions unless otherwise specified)

 

6.

Interest

 

		Three Months Ended March 31,
		2015				2014
Interest Expense on:
Debt		$	95			$	112
The Bow office building			16				19
Capital leases			9				9
Other			5				7
		$	125			$	147

 

7.	Foreign Exchange (Gain) Loss, Net

 

		Three Months Ended March 31,
		2015				2014
Unrealized Foreign Exchange (Gain) Loss on:
Translation of U.S. dollar debt issued from Canada		$	464			$	204
Translation of U.S. dollar risk management contracts issued from Canada			(35	)			(7	)
Translation of intercompany notes			130				—
			559				197
Foreign Exchange on Intercompany Transactions			(2	)			26
Other Monetary Revaluations and Settlements			99				1
		$	656			$	224

 

8.	Income Taxes

 

		Three Months Ended March 31,
		2015				2014
Current Tax
Canada		$	13			$	7
United States			1				3
Other countries			2				6
Total Current Tax Expense			16				16
Deferred Tax
Canada			(323	)			4
United States			(760	)			2
Other countries			120				6
Total Deferred Tax Expense (Recovery)			(963	)			12
		$	(947	)		$	28

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 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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Q1 Report  |  for the period ended March 31, 2015

 

 

 

Notes to Condensed Consolidated Financial Statements (unaudited)

 

(All amounts in $ millions unless otherwise specified)

 

9.	Property, Plant and Equipment, Net

 

		As at March 31, 2015												As at December 31, 2014
		Accumulated												Accumulated
		Cost				DD&A (1)				Net				Cost				DD&A (1)				Net
Canadian Operations
Proved properties		$	16,016			$	(15,257	)		$	759			$	18,271			$	(16,566	)		$	1,705
Unproved properties			420				—				420				478				—				478
Other			125				—				125				155				—				155
			16,561				(15,257	)			1,304				18,904				(16,566	)			2,338
USA Operations
Proved properties			25,009				(18,508	)			6,501				24,279				(16,260	)			8,019
Unproved properties			5,564				—				5,564				5,655				—				5,655
Other			101				—				101				143				—				143
			30,674				(18,508	)			12,166				30,077				(16,260	)			13,817
Market Optimization			7				(6	)			1				8				(7	)			1
Corporate & Other			2,274				(583	)			1,691				2,470				(611	)			1,859
		$	49,516			$	(34,354	)		$	15,162			$	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 $56 million which have been capitalized during the three months ended March 31, 2015 (2014 - $101 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 months ended March 31, 2015, the Company recognized a ceiling test impairment of $1,916 million (2014 - nil) before tax in the U.S. cost centre, which is included within accumulated DD&A in the table above. The impairment resulted primarily from the decline in the 12-month average trailing commodity prices which reduced proved reserves volumes and values. There was no ceiling test impairment in the Canadian cost centre for the three months ended March 31, 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
March 31, 2015			3.88				3.86				82.72				84.80
December 31, 2014			4.34				4.63				94.99				96.40
March 31, 2014			3.99				3.83				98.46				96.84

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 15.

As at March 31, 2015, the total carrying value of assets under capital lease was $464 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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Q1 Report  |  for the period ended March 31, 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 March 31, 2015, Corporate and Other property, plant and equipment and total assets include a carrying value of $1,303 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 March 31, 2015				As at December 31, 2014
Canadian Dollar Denominated Debt
5.80% due January 18, 2018		$	750			$	591			$	647
U.S. Dollar Denominated Debt
Revolving credit and term loan borrowings							1,211				1,277
U.S. Unsecured Notes
5.90% due December 1, 2017							700				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
							6,611				6,677
Total Principal							7,202				7,324
Increase in Value of Debt Acquired							30				34
Debt Discounts							(16	)			(18	)
Current Portion of Long-Term Debt							(1,291	)			—
						$	5,925			$	7,340

Long-term debt is accounted for at amortized cost using the effective interest method of amortization. As at March 31, 2015, total long-term debt had a carrying value of $7,216 million and a fair value of $8,048 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. Accordingly, these notes are presented within the current portion of long-term debt on the Company’s Condensed Consolidated Balance Sheet as at March 31, 2015. 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.

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.

 

 

 

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

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Q1 Report  |  for the period ended March 31, 2015

 

 

 

Notes to Condensed Consolidated Financial Statements (unaudited)

 

(All amounts in $ millions unless otherwise specified)

 

11.	Other Liabilities and Provisions

 

		As at March 31, 2015				As at December 31, 2014
The Bow Office Building (See Note 9)		$	1,358			$	1,486
Capital Lease Obligations (See Note 9)			424				473
Unrecognized Tax Benefits			238				279
Pensions and Other Post-Employment Benefits			147				144
Long-Term Incentives (See Note 17)			21				70
Other			37				32
		$	2,225			$	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		$	55			$	74			$	75			$	75			$	76			$	1,511			$	1,866
Sublease Recoveries		$	(27	)		$	(36	)		$	(37	)		$	(37	)		$	(37	)		$	(743	)		$	(917	)

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 15.

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		$	74			$	98			$	99			$	99			$	99			$	232			$	701
Less Amounts Representing Interest			31				41				37				33				29				50				221
Present Value of Expected Future Lease Payments		$	43			$	57			$	62			$	66			$	70			$	182			$	480

 

 

 

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

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Q1 Report  |  for the period ended March 31, 2015

 

 

 

Notes to Condensed Consolidated Financial Statements (unaudited)

 

(All amounts in $ millions unless otherwise specified)

 

12.	Asset Retirement Obligation

 

		As at March 31, 2015				As at December 31, 2014
Asset Retirement Obligation, Beginning of Year		$	913			$	966
Liabilities Incurred and Acquired (See Note 4)			9				85
Liabilities Settled and Divested			(86	)			(188	)
Change in Estimated Future Cash Outflows			—				35
Accretion Expense			12				52
Foreign Currency Translation			(34	)			(37	)
Asset Retirement Obligation, End of Period		$	814			$	913
Current Portion		$	41			$	43
Long-Term Portion			773				870
		$	814			$	913

 

13.	Share Capital

Authorized

The Company is authorized to issue an unlimited number of no par value common shares, an unlimited number of first preferred shares and an unlimited number of second preferred shares.

Issued and Outstanding

 

		As at March 31, 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			1.3				14				0.3				5
Common Shares Outstanding, End of Period			840.9			$	3,562				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 three months ended March 31, 2015, Encana issued 1,267,680 common shares totaling $14 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 March 31, 2015, Encana paid dividends of $0.07 per common share totaling $52 million (2014 - $0.07 per common share totaling $52 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 months ended March 31, 2015, the dividends paid included $14 million in common shares which were issued in lieu of cash dividends under the DRIP (2014 - $1 million).

 

 

 

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

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Q1 Report  |  for the period ended March 31, 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 March 31,
(millions, except per share amounts)		2015				2014
Net Earnings (Loss)		$	(1,707	)		$	116
Number of Common Shares:
Weighted average common shares outstanding - Basic			757.8				741.0
Effect of dilutive securities			—				—
Weighted average common shares outstanding - Diluted			757.8				741.0
Net Earnings (Loss) per Common Share
Basic		$	(2.25	)		$	0.16
Diluted		$	(2.25	)		$	0.16

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 March 31, 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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Q1 Report  |  for the period ended March 31, 2015

 

 

 

Notes to Condensed Consolidated Financial Statements (unaudited)

 

(All amounts in $ millions unless otherwise specified)

 

14.	Accumulated Other Comprehensive Income

 

		Three Months Ended March 31,
		2015				2014
Foreign Currency Translation Adjustment
Balance, Beginning of Year		$	715			$	693
Current Period Change in Foreign Currency Translation Adjustment			478				24
Balance, End of Period		$	1,193			$	717
Pension and Other Post-Employment Benefit Plans
Balance, Beginning of Year		$	(26	)		$	(9	)
Reclassification of Net Actuarial (Gains) and Losses to Net Earnings (See Note 18)			1				—
Income Taxes			—				—
Balance, End of Period		$	(25	)		$	(9	)
Total Accumulated Other Comprehensive Income		$	1,168			$	708

 

15.	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 March 31, 2015, Encana’s capital lease obligation of $410 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.

 

 

 

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

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Q1 Report  |  for the period ended March 31, 2015

 

 

 

Notes to Condensed Consolidated Financial Statements (unaudited)

 

(All amounts in $ millions unless otherwise specified)

 

15.	Variable Interest Entities (continued)

 

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 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 is assessed in the eighth year of the assets’ service period based on whether there is an overall shortfall of total system cash flows from natural gas gathered and compressed under certain agreements. The potential payout amount can be reduced in the event VMLP procures unused 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 $1,183 million as at March 31, 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 requirements are highly uncertain as the payout amount is contingent on future production estimates, pace of development and capacity contracted to third parties. As at March 31, 2015, accounts payable and accrued liabilities includes $5 million related to the take or pay commitment. The take or pay for volumes committed to certain gathering and processing agreements are included in Note 21.

 

16.	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 $124 million, of which $3 million remains accrued as at March 31, 2015. Total restructuring charges are expected to be approximately $134 million before tax. For the three months ended March 31, 2015, no restructuring charges were incurred (2014 - $15 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 Company’s Condensed Consolidated Statement of Earnings.

 

17.	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 March 31, 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			0.50	%			0.50	%
Dividend Yield			2.51	%			2.46	%
Expected Volatility Rate			31.97	%			30.06	%
Expected Term			1.9 yrs				1.9 yrs
Market Share Price		US$	11.15			C$	14.14

 

 

 

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

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Q1 Report  |  for the period ended March 31, 2015

 

 

 

Notes to Condensed Consolidated Financial Statements (unaudited)

 

(All amounts in $ millions unless otherwise specified)

 

17.	Compensation Plans (continued)

 

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

 

		Three Months Ended March 31,
		2015				2014
Compensation Costs of Transactions Classified as Cash-Settled		$	(6	)		$	72
Compensation Costs of Transactions Classified as Equity-Settled (1)			—				(2	)
Total Share-Based Compensation Costs			(6	)			70
Less: Total Share-Based Compensation Costs Capitalized			3				(26	)
Total Share-Based Compensation Expense		$	(3	)		$	44
Recognized on the Condensed Consolidated Statement of Earnings in:
Operating expense		$	(2	)		$	20
Administrative expense			(1	)			24
		$	(3	)		$	44

 

(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 March 31, 2015, the liability for share-based payment transactions totaled $82 million ($99 million as at December 31, 2014), of which $61 million ($29 million as at December 31, 2014) is recognized in accounts payable and accrued liabilities in the Condensed Consolidated Balance Sheet.

 

		As at March 31, 2015				As at December 31, 2014
Liability for Cash-Settled Share-Based Payment Transactions:
Unvested		$	64			$	78
Vested			18				21
		$	82			$	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.

 

Three Months Ended March 31, 2015 (thousands of units)
TSARs			1,934
SARs			1,444
PSUs			2,291
DSUs			158
RSUs			6,353

 

 

 

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

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Q1 Report  |  for the period ended March 31, 2015

 

 

 

Notes to Condensed Consolidated Financial Statements (unaudited)

 

(All amounts in $ millions unless otherwise specified)

 

18.	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 three months ended March 31 as follows:

 

		Pension Benefits								OPEB								Total
		2015				2014				2015				2014				2015				2014
Defined Benefit Plan Expense		$	1			$	—			$	3			$	3			$	4			$	3
Defined Contribution Plan Expense			8				8				—				—				8				8
Total Benefit Plans Expense		$	9			$	8			$	3			$	3			$	12			$	11

Of the total benefit plans expense, $9 million (2014 - $8 million) was included in operating expense and $3 million (2014 - $3 million) was included in administrative expense.

The defined periodic pension and OPEB expense for the three months ended March 31 are as follows:

 

		Pension Benefits								OPEB								Total
		2015				2014				2015				2014				2015				2014
Current Service Costs		$	1			$	1			$	2			$	2			$	3			$	3
Interest Cost			2				3				1				1				3				4
Expected Return On Plan Assets			(3	)			(4	)			—				—				(3	)			(4	)
Amounts Reclassified From Accumulated Other Comprehensive Income:
Amortization of net actuarial (gains) and losses			1				—				—				—				1				—
Total Defined Benefit Plan Expense		$	1			$	—			$	3			$	3			$	4			$	3

The amounts recognized in other comprehensive income for the three months ended March 31 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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Q1 Report  |  for the period ended March 31, 2015

 

 

 

Notes to Condensed Consolidated Financial Statements (unaudited)

 

(All amounts in $ millions unless otherwise specified)

 

19.	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 20. 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 March 31, 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		$	—			$	629			$	—			$	629			$	(22	)		$	607
Long-term			—				16				—				16				(3	)			13
Risk Management Liabilities
Current			—				22				13				35				(22	)			13
Long-term			—				4				11				15				(3	)			12

 

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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Q1 Report  |  for the period ended March 31, 2015

 

 

 

Notes to Condensed Consolidated Financial Statements (unaudited)

 

(All amounts in $ millions unless otherwise specified)

 

19.	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 March 31, 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 three months ended March 31 is presented below:

 

		Risk Management
		2015				2014
Balance, Beginning of Year		$	(18	)		$	(7	)
Total Gains (Losses)			(11	)			(1	)
Purchases and Settlements:
Purchases			—				—
Settlements			5				1
Transfers in and out of Level 3			—				—
Balance, End of Period		$	(24	)		$	(7	)
Change in unrealized gains (losses) related to assets and liabilities held at end of period		$	(9	)		$	(1	)

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

 

		Valuation Technique		Unobservable Input		As at March 31, 2015		As at December 31, 2014
Risk Management - Power		Discounted Cash Flow		Forward prices ($/Megawatt Hour)		$35.06 - $39.75		$40.70 - $48.50

A 10 percent increase or decrease in estimated forward power prices would cause a corresponding $4 million ($5 million as at December 31, 2014) increase or decrease to net risk management assets and liabilities.

 

 

 

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

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Q1 Report  |  for the period ended March 31, 2015

 

 

 

Notes to Condensed Consolidated Financial Statements (unaudited)

 

(All amounts in $ millions unless otherwise specified)

 

20.	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 19 for a discussion of fair value measurements.

Unrealized Risk Management Position

 

		As at March 31, 2015				As at December 31, 2014
Risk Management Assets
Current		$	607			$	707
Long-term			13				65
			620				772
Risk Management Liabilities
Current			13				20
Long-term			12				7
			25				27
Net Risk Management Assets		$	595			$	745

Commodity Price Positions as at March 31, 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			$	413
Basis Contracts (1)						2015-2018							62
Other Financial Positions													1
Natural Gas Fair Value Position													476
Crude Oil Contracts
Fixed Price Contracts
WTI Fixed Price			55.8 Mbbls/d			2015			62.09 US$/bbl				146
WTI Fixed Price			1.2 Mbbls/d			2016			92.35 US$/bbl				16
Basis Contracts (2)						2015-2016							(19	)
Crude Oil Fair Value Position													143
Power Purchase Contracts
Fair Value Position													(24	)
Total Fair Value Position												$	595

 

(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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Q1 Report  |  for the period ended March 31, 2015

 

 

 

Notes to Condensed Consolidated Financial Statements (unaudited)

 

(All amounts in $ millions unless otherwise specified)

 

20.	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)								Unrealized Gain (Loss)
		Three Months Ended March 31,								Three Months Ended March 31,
		2015				2014				2015				2014
Revenues, Net of Royalties		$	245			$	(140	)		$	(128	)		$	(284	)
Transportation and Processing			(5	)			(1	)			(8	)			(1	)
Gain (Loss) on Risk Management		$	240			$	(141	)		$	(136	)		$	(285	)

Reconciliation of Unrealized Risk Management Positions from January 1 to March 31

 

		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			104			$	104			$	(426	)
Foreign Exchange Translation Adjustment on Canadian Dollar Contracts			2
Settlement of Athlon Crude Oil Contracts from Business Combination			(16	)
Fair Value of Contracts Realized During the Period			(240	)			(240	)			141
Fair Value of Contracts, End of Period		$	595			$	(136	)		$	(285	)

 

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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Q1 Report  |  for the period ended March 31, 2015

 

 

 

Notes to Condensed Consolidated Financial Statements (unaudited)

 

(All amounts in $ millions unless otherwise specified)

 

20.	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 three months ended March 31 as follows:

 

		2015								2014
		10% Price Increase				10% Price Decrease				10% Price Increase				10% Price Decrease
Natural Gas Price		$	(70	)		$	70			$	(385	)		$	385
Crude Oil Price			(78	)			78				(29	)			29
Power Price			4				(4	)			7				(7	)

Credit Risk

Credit risk arises from the potential that the Company may incur a loss if a counterparty to a financial instrument fails to meet its obligation in accordance with agreed terms. This credit risk exposure is mitigated through the use of Board-approved credit policies governing the 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 March 31, 2015, the Company had no significant collateral balances posted or received and there were no credit derivatives in place.

As at March 31, 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 March 31, 2015, approximately 94 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 March 31, 2015, Encana had three 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 March 31, 2015, these counterparties accounted for 17 percent, 15 percent and 14 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 March 31, 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, $1.6 billion remained unused. The facilities remain committed through June 2018.

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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Q1 Report  |  for the period ended March 31, 2015

 

 

 

Notes to Condensed Consolidated Financial Statements (unaudited)

 

(All amounts in $ millions unless otherwise specified)

 

20.	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		$	1,903			$	—			$	—			$	—			$	—			$	1,903
Risk Management Liabilities			13				12				—				—				—				25
Long-Term Debt (1)			1,823				610				2,295				1,610				6,313				12,651

 

(1)	Principal and interest.

Included in Encana’s long-term debt obligations of $12,651 million at March 31, 2015 are $1,211 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.

To mitigate the exposure to the fluctuating U.S./Canadian dollar exchange rate, Encana maintains a mix of both U.S. dollar and Canadian dollar debt and may also enter into foreign exchange derivatives. As at March 31, 2015, Encana had $6.6 billion in U.S. dollar debt issued from Canada that was subject to foreign exchange exposure ($6.7 billion as at December 31, 2014) and $0.6 billion in debt that was not subject to foreign exchange exposure ($0.6 billion as at December 31, 2014). There were no foreign exchange derivatives outstanding as at March 31, 2015.

Encana’s foreign exchange (gain) loss primarily includes unrealized foreign exchange gains and losses on the translation 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 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 $48 million change in foreign exchange (gain) loss as at March 31, 2015 (2014 - $48 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 March 31, 2015.

As at March 31, 2015, the Company had floating rate debt of $1,211 million. Accordingly, the sensitivity in net earnings for each one percent change in interest rates on floating rate debt was $9 million (2014 - nil).

 

 

 

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

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Q1 Report  |  for the period ended March 31, 2015

 

 

 

Notes to Condensed Consolidated Financial Statements (unaudited)

 

(All amounts in $ millions unless otherwise specified)

 

21.	Commitments and Contingencies

Commitments

The following table outlines the Company’s commitments as at March 31, 2015:

 

		Expected Future Payments
(undiscounted)		2015				2016				2017				2018				2019				Thereafter				Total
Transportation and Processing		$	598			$	787			$	779			$	798			$	674			$	3,085			$	6,721
Drilling and Field Services			164				128				90				47				14				16				459
Operating Leases			24				27				22				21				8				20				122
Total		$	786			$	942			$	891			$	866			$	696			$	3,121			$	7,302

Included within transportation and processing in the table above are certain commitments associated with midstream service agreements with VMLP as described in Note 15.

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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Q1 Report  |  for the period ended March 31, 2015

 

 

 

Supplemental Financial Information (unaudited)

 

Financial Results

 

		2015				2014
($ millions, except per share amounts)		Q1				Year				Q4				Q3				Q2				Q1
Cash Flow (1)			495				2,934				377				807				656				1,094
Per share - Diluted (3)			0.65				3.96				0.51				1.09				0.89				1.48
Operating Earnings (2)			9				1,002				35				281				171				515
Per share - Diluted (3)			0.01				1.35				0.05				0.38				0.23				0.70
Net Earnings (Loss) Attributable to Common Shareholders			(1,707	)			3,392				198				2,807				271				116
Per share - Diluted (3)			(2.25	)			4.58				0.27				3.79				0.37				0.16
Effective Tax Rate using Canadian Statutory Rate			25.7	%			25.7	%
Foreign Exchange Rates (US$ per C$1)
Average			0.806				0.905				0.881				0.918				0.917				0.906
Period end			0.789				0.862				0.862				0.892				0.937				0.905
Cash Flow Summary
Cash From (Used in) Operating Activities			482				2,667				261				696				767				943
Deduct (Add back):
Net change in other assets and liabilities			(7	)			(43	)			(15	)			(11	)			(8	)			(9	)
Net change in non-cash working capital			(6	)			(9	)			(141	)			155				119				(142	)
Cash tax on sale of assets			—				(215	)			40				(255	)			—				—
Cash Flow (1)			495				2,934				377				807				656				1,094
Operating Earnings Summary
Net Earnings (Loss) Attributable to Common Shareholders			(1,707	)			3,392				198				2,807				271				116
After-tax (addition) deduction:
Unrealized hedging gain (loss)			(98	)			306				341				160				8				(203	)
Impairments			(1,222	)			—				—				—				—				—
Restructuring charges			—				(24	)			(4	)			(5	)			(5	)			(10	)
Non-operating foreign exchange gain (loss)			(508	)			(407	)			(151	)			(218	)			156				(194	)
Gain (loss) on divestitures			10				2,523				(11	)			2,399				135				—
Income tax adjustments			102				(8	)			(12	)			190				(194	)			8
Operating Earnings (2)			9				1,002				35				281				171				515

 

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

(2)

Operating Earnings is a non-GAAP measure defined as net earnings 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)	Net earnings attributable to common shareholders, operating earnings and cash flow per common share are calculated using the weighted average number of Encana common shares outstanding as follows:

 

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

 

 

 

		Supplemental Information Prepared in US$

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Q1 Report  |  for the period ended March 31, 2015

 

 

 

Supplemental Financial & Operating Information (unaudited)

 

Financial Metrics

 

		2015				2014
		Q1				Year
Debt to Debt Adjusted Cash Flow			2.6x				2.1x
Debt to Adjusted Capitalization			29	%			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)		Q1				Year				Q4				Q3				Q2				Q1
Capital Investment
Canadian Operations			151				1,226				302				293				350				281
USA Operations			583				1,285				548				305				206				226
Market Optimization			—				—				—				(2	)			1				1
Corporate & Other			2				15				7				2				3				3
Capital Investment			736				2,526				857				598				560				511
Net Acquisitions & (Divestitures)			(838	)			(1,329	)			50				(2,007	)			652				(24	)
Net Capital Investment			(102	)			1,197				907				(1,409	)			1,212				487

Capital Investment

 

		2015				2014
($ millions)		Q1				Year				Q4				Q3				Q2				Q1
Capital Investment
Montney (1)			79				781				159				204				210				208
Duvernay			70				328				118				58				81				71
Eagle Ford			197				274				149				113				12				—
Permian			217				117				117				—				—				—
DJ Basin			88				277				81				68				69				59
San Juan			36				287				96				89				50				52
			687				2,064				720				532				422				390
Other Upstream Operations (1, 2)			47				447				130				66				134				117
Market Optimization			—				—				—				(2	)			1				1
Corporate & Other			2				15				7				2				3				3
Capital Investment			736				2,526				857				598				560				511

 

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

(2)	Other Upstream Operations includes capital investment for Encana’s base production properties as well as capital investment for prospective plays which are under appraisal, including the Tuscaloosa Marine Shale (“TMS”). Q1 2015 capital investment for the TMS was $26 million (Q1 2014 - $20 million).

 

 

 

		Supplemental Information Prepared in US$

---

Q1 Report  |  for the period ended March 31, 2015

 

 

 

Supplemental Financial & Operating Information (unaudited)

 

 

Production Volumes - After Royalties

 

		2015				2014
(average)		Q1				Year				Q4				Q3				Q2				Q1
Natural Gas (MMcf/d)			1,857				2,350				1,861				2,199				2,541				2,809
Oil (Mbbls/d)			79.2				49.4				68.8				62.1				34.2				32.1
NGLs (Mbbls/d)			41.5				37.4				37.6				41.9				34.0				35.8
Oil & NGLs (Mbbls/d)			120.7				86.8				106.4				104.0				68.2				67.9
Total (MBOE/d)			430.1				478.5				416.7				470.6				491.8				536.1

Production Volumes - After Royalties

 

		2015				2014
(average)		Q1				Year				Q4				Q3				Q2				Q1
Natural Gas (MMcf/d)
Canadian Operations			1,128				1,378				1,111				1,374				1,463				1,568
USA Operations			729				972				750				825				1,078				1,241
			1,857				2,350				1,861				2,199				2,541				2,809
Oil (Mbbls/d)
Canadian Operations			6.6				13.6				9.4				14.7				13.9				16.4
USA Operations			72.6				35.8				59.4				47.4				20.3				15.7
			79.2				49.4				68.8				62.1				34.2				32.1
NGLs (Mbbls/d)
Canadian Operations			21.2				23.6				18.8				27.6				23.5				24.6
USA Operations			20.3				13.8				18.8				14.3				10.5				11.2
			41.5				37.4				37.6				41.9				34.0				35.8
Oil & NGLs (Mbbls/d)
Canadian Operations			27.8				37.2				28.2				42.3				37.4				41.0
USA Operations			92.9				49.6				78.2				61.7				30.8				26.9
			120.7				86.8				106.4				104.0				68.2				67.9
Total (MBOE/d)
Canadian Operations			215.8				266.9				213.4				271.4				281.4				302.4
USA Operations			214.3				211.6				203.3				199.2				210.4				233.7
			430.1				478.5				416.7				470.6				491.8				536.1

Oil & NGLs Production Volumes - After Royalties

 

		2015								2014
(average Mbbls/d)		Q1				% of Total				Year				% of Total
Oil			79.2				66				49.4				57
Plant Condensate			14.0				11				12.0				14
Butane			7.2				6				6.8				8
Propane			9.7				8				10.2				11
Ethane			10.6				9				8.4				10
			120.7				100				86.8				100

 

 

 

		Supplemental Information Prepared in US$

---

Q1 Report  |  for the period ended March 31, 2015

 

 

 

Supplemental Financial & Operating Information (unaudited)

 

 

Results of Operations

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

 

		2015				2014
($ millions)		Q1				Year				Q4				Q3				Q2				Q1
Natural Gas - Canadian Operations
Revenues, Net of Royalties, excluding Hedging			396				2,468				402				480				569				1,017
Realized Financial Hedging Gain (Loss)			154				(74	)			25				20				(44	)			(75	)
Expenses
Production and mineral taxes			—				5				2				1				—				2
Transportation and processing			163				773				177				186				209				201
Operating			36				279				57				66				72				84
Operating Cash Flow			351				1,337				191				247				244				655
Natural Gas - USA Operations
Revenues, Net of Royalties, excluding Hedging			195				1,640				274				307				463				596
Realized Financial Hedging Gain (Loss)			54				(85	)			13				10				(43	)			(65	)
Expenses
Production and mineral taxes			4				44				11				(10	)			14				29
Transportation and processing			151				651				149				162				177				163
Operating			49				235				52				50				65				68
Operating Cash Flow			45				625				75				115				164				271
Natural Gas - Total Operations
Revenues, Net of Royalties, excluding Hedging			591				4,108				676				787				1,032				1,613
Realized Financial Hedging Gain (Loss)			208				(159	)			38				30				(87	)			(140	)
Expenses
Production and mineral taxes			4				49				13				(9	)			14				31
Transportation and processing			314				1,424				326				348				386				364
Operating			85				514				109				116				137				152
Operating Cash Flow			396				1,962				266				362				408				926
Oil & NGLs - Canadian Operations
Revenues, Net of Royalties, excluding Hedging			77				872				149				251				227				245
Realized Financial Hedging Gain (Loss)			2				18				24				(1	)			(5	)			—
Expenses
Production and mineral taxes			—				10				—				3				4				3
Transportation and processing			14				62				16				16				16				14
Operating			6				28				10				8				4				6
Operating Cash Flow			59				790				147				223				198				222
Oil & NGLs - USA Operations
Revenues, Net of Royalties, excluding Hedging			295				1,258				412				452				215				179
Realized Financial Hedging Gain (Loss)			38				60				65				1				(6	)			—
Expenses
Production and mineral taxes			15				74				23				23				15				13
Transportation and processing			4				7				3				4				—				—
Operating			75				115				51				44				12				8
Operating Cash Flow			239				1,122				400				382				182				158
Oil & NGLs - Total Operations
Revenues, Net of Royalties, excluding Hedging			372				2,130				561				703				442				424
Realized Financial Hedging Gain (Loss)			40				78				89				—				(11	)			—
Expenses
Production and mineral taxes			15				84				23				26				19				16
Transportation and processing			18				69				19				20				16				14
Operating			81				143				61				52				16				14
Operating Cash Flow			298				1,912				547				605				380				380

 

 

 

		Supplemental Information Prepared in US$

---

Q1 Report  |  for the period ended March 31, 2015

 

 

 

Supplemental Oil and Gas Operating Statistics (unaudited)

 

Operating Statistics - After Royalties

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

 

		2015				2014
		Q1				Year				Q4				Q3				Q2				Q1
Natural Gas - Canadian Operations ($/Mcf)
Price (1)			3.89				4.89				3.93				3.78				4.27				7.17
Production and mineral taxes			—				0.01				0.01				0.01				—				0.01
Transportation and processing			1.60				1.53				1.73				1.47				1.57				1.42
Operating			0.35				0.55				0.55				0.52				0.55				0.59
Netback			1.94				2.80				1.64				1.78				2.15				5.15
Natural Gas - USA Operations ($/Mcf)
Price			2.97				4.62				3.95				4.05				4.72				5.34
Production and mineral taxes			0.06				0.12				0.17				(0.14	)			0.15				0.26
Transportation and processing			2.30				1.83				2.16				2.13				1.80				1.46
Operating			0.75				0.66				0.75				0.65				0.67				0.61
Netback			(0.14	)			2.01				0.87				1.41				2.10				3.01
Natural Gas - Total Operations ($/Mcf)
Price (2)			3.53				4.78				3.94				3.88				4.46				6.37
Production and mineral taxes			0.02				0.06				0.08				(0.05	)			0.06				0.12
Transportation and processing			1.88				1.66				1.90				1.72				1.67				1.44
Operating			0.51				0.60				0.63				0.57				0.60				0.60
Netback			1.12				2.46				1.33				1.64				2.13				4.21
Oil & NGLs - Canadian Operations ($/bbl)
Price			30.65				64.16				57.50				64.79				66.13				66.36
Production and mineral taxes			0.04				0.71				0.10				0.67				1.12				0.80
Transportation and processing			5.82				4.52				5.92				4.21				4.60				3.80
Operating			2.31				2.09				4.00				2.05				1.06				1.75
Netback			22.48				56.84				47.48				57.86				59.35				60.01
Oil & NGLs - USA Operations ($/bbl)
Price			35.18				69.54				57.30				79.43				77.46				73.61
Production and mineral taxes			1.80				4.10				3.16				4.18				5.19				5.46
Transportation and processing			0.43				0.39				0.49				0.63				—				—
Operating			8.96				6.36				7.11				7.80				4.29				3.16
Netback			23.99				58.69				46.54				66.82				67.98				64.99
Oil & NGLs - Total Operations ($/bbl)
Price			34.13				67.24				57.35				73.48				71.23				69.23
Production and mineral taxes			1.40				2.65				2.35				2.75				2.95				2.65
Transportation and processing			1.67				2.16				1.93				2.09				2.53				2.30
Operating			7.43				4.54				6.29				5.46				2.51				2.31
Netback			23.63				57.89				46.78				63.18				63.24				61.97
Total Operations Netback - Canadian Operations ($/BOE)
Price			24.30				34.21				28.06				29.21				31.02				46.20
Production and mineral taxes			0.02				0.15				0.09				0.15				0.16				0.18
Transportation and processing			9.12				8.55				9.79				8.10				8.76				7.87
Operating			2.14				3.14				3.39				2.96				2.98				3.29
Netback			13.02				22.37				14.79				18.00				19.12				34.86
Total Operations Netback - USA Operations ($/BOE)
Price			25.34				37.53				36.64				41.38				35.48				36.82
Production and mineral taxes			0.97				1.53				1.84				0.72				1.51				1.99
Transportation and processing			8.02				8.52				8.17				9.03				9.23				7.75
Operating			6.44				4.53				5.51				5.12				4.05				3.60
Netback			9.91				22.95				21.12				26.51				20.69				23.48
Total Operations Netback ($/BOE)
Price			24.82				35.67				32.25				34.36				32.93				42.12
Production and mineral taxes			0.49				0.76				0.94				0.39				0.74				0.97
Transportation and processing			8.57				8.54				9.00				8.50				8.96				7.82
Operating (3)			4.27				3.76				4.43				3.87				3.44				3.43
Netback			11.49				22.61				17.88				21.60				19.79				29.90

 

(1)	Canadian Operations price reflects Deep Panuke price for Q1 2015 of $10.68/Mcf on natural gas production volumes of 182 MMcf/d. Excluding the impact of the Deep Panuke operations, the natural gas price for Q1 2015 is $2.59/Mcf.

(2)	Excluding the impact of the Deep Panuke operations, the natural gas price for Q1 2015 is $2.76/Mcf.

(3)	Q1 2015 operating expense includes a recovery of costs related to long-term incentives of $0.04/B0E (Q1 2014 - costs of $0.32/B0E).

 

 

 

		Supplemental Information Prepared in US$

---

Q1 Report  |  for the period ended March 31, 2015

 

 

 

Supplemental Oil and Gas Operating Statistics (unaudited)

 

 

Operating Statistics - After Royalties (continued)

 

Impact of Realized Financial Hedging

 

		2015				2014
		Q1				Year				Q4				Q3				Q2				Q1
Natural Gas ($/Mcf)
Canadian Operations			1.52				(0.15	)			0.24				0.16				(0.33	)			(0.53	)
USA Operations			0.82				(0.24	)			0.19				0.12				(0.44	)			(0.58	)
Total Operations			1.25				(0.19	)			0.22				0.15				(0.38	)			(0.55	)
Oil & NGLs ($/bbl)
Canadian Operations			0.78				1.36				9.35				(0.31	)			(1.22	)			(0.09	)
USA Operations			4.58				3.29				8.94				0.25				(2.28	)			0.04
Total Operations			3.70				2.46				9.05				0.02				(1.70	)			(0.04	)
Total ($/BOE)
Canadian Operations			8.04				(0.57	)			2.49				0.78				(1.89	)			(2.77	)
USA Operations			4.78				(0.33	)			4.15				0.58				(2.57	)			(3.07	)
Total Operations			6.42				(0.46	)			3.30				0.70				(2.18	)			(2.90	)

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

 

		2015				2014
		Q1				Year				Q4				Q3				Q2				Q1
Natural Gas Price ($/Mcf)
Canadian Operations			5.41				4.74				4.17				3.94				3.94				6.64
USA Operations			3.79				4.38				4.14				4.17				4.28				4.76
Total Operations			4.78				4.59				4.16				4.03				4.08				5.82
Natural Gas Netback ($/Mcf)
Canadian Operations			3.46				2.65				1.88				1.94				1.82				4.62
USA Operations			0.68				1.77				1.06				1.53				1.66				2.43
Total Operations			2.37				2.27				1.55				1.79				1.75				3.66
Oil & NGLs Price ($/bbl)
Canadian Operations			31.43				65.52				66.85				64.48				64.91				66.27
USA Operations			39.76				72.83				66.24				79.68				75.18				73.65
Total Operations			37.83				69.70				66.40				73.50				69.53				69.19
Oil & NGLs Netback ($/bbl)
Canadian Operations			23.26				58.20				56.83				57.55				58.13				59.92
USA Operations			28.57				61.98				55.48				67.07				65.70				65.03
Total Operations			27.33				60.35				55.83				63.20				61.54				61.93
Total Price ($/BOE)
Canadian Operations			32.34				33.64				30.55				29.99				29.13				43.43
USA Operations			30.12				37.20				40.79				41.96				32.91				33.75
Total Operations			31.24				35.21				35.55				35.06				30.75				39.22
Total Netback ($/BOE)
Canadian Operations			21.06				21.80				17.28				18.78				17.23				32.09
USA Operations			14.69				22.62				25.27				27.09				18.12				20.41
Total Operations			17.91				22.15				21.18				22.30				17.61				27.00

 

 

 

		Supplemental Information Prepared in US$

---

Q1 Report  |  for the period ended March 31, 2015

 

 

 

Supplemental Oil and Gas Operating Statistics (unaudited)

 

 

Results by Play

 

		2015				2014
		Q1				Year				Q4				Q3				Q2				Q1
Natural Gas Production (MMcf/d) - After Royalties
Canadian Operations
Montney (1)			717				639				687				644				604				620
Duvernay			16				11				12				15				9				8
Other Upstream Operations (2)
Wheatland (3)			111				292				249				291				305				324
Bighorn			4				158				(3	)			162				230				246
Deep Panuke			182				190				79				186				243				253
Other and emerging (1)			98				88				87				76				72				117
Total Canadian Operations			1,128				1,378				1,111				1,374				1,463				1,568
USA Operations
Eagle Ford			36				19				35				35				5				—
Permian			34				5				20				—				—				—
DJ Basin			49				43				49				38				43				40
San Juan			13				8				8				9				7				7
Other Upstream Operations (2)
Piceance			343				402				367				398				407				436
Haynesville			230				311				252				298				365				331
Jonah			—				100				—				—				124				282
East Texas			—				57				—				21				97				113
Other and emerging			24				27				19				26				30				32
Total USA Operations			729				972				750				825				1,078				1,241
Oil & NGLs Production (Mbbls/d) - After Royalties
Canadian Operations
Montney (1)			23.3				18.9				24.8				20.8				13.3				16.2
Duvernay			2.8				2.1				2.5				2.6				1.8				1.4
Other Upstream Operations (2)
Wheatland (3)			1.7				8.6				2.0				9.9				11.3				11.3
Bighorn			—				7.5				(1.5	)			8.7				11.0				12.1
Other and emerging (1)			—				0.1				0.4				0.3				—				—
Total Canadian Operations			27.8				37.2				28.2				42.3				37.4				41.0
USA Operations
Eagle Ford			36.0				19.8				36.1				37.6				5.0				—
Permian			26.7				3.5				13.8				—				—				—
DJ Basin			14.3				11.6				14.0				11.8				10.1				10.5
San Juan			6.7				3.9				5.6				3.5				3.9				2.7
Other Upstream Operations (2)
Piceance			3.7				5.0				4.3				4.8				5.3				5.4
Jonah			—				1.8				—				0.2				2.5				4.7
East Texas			—				0.5				—				—				1.0				1.2
Other and emerging			5.5				3.5				4.4				3.8				3.0				2.4
Total USA Operations			92.9				49.6				78.2				61.7				30.8				26.9

 

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

(2)	Other Upstream Operations includes results from plays that are not part of the 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$

---

Q1 Report  |  for the period ended March 31, 2015

 

 

 

Supplemental Oil and Gas Operating Statistics (unaudited)

 

 

Results by Play (continued)

 

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

---

Encana Corporation
Further information on Encana Corporation
is available on the company’s website,
www.encana.com, or by contacting:
INVESTOR CONTACT:
Brian Dutton
Director, Investor Relations 403.645.2285
Patti Posadowski
Sr. Advisor, Investor Relations
403.645.2252
MEDIA CONTACT:
Jay Averill
Director, Media Relations 403.645.4747
GENERAL INQUIRIES
Encana Corporation 500 Centre Street SE PO Box 2850
Calgary, AB , Canada T2P 2S5 Phone: 403.645.2000
Fax: 403.645.3400
encana