UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

[X]

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2018

or

[  ]

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number 1-15226

 

ENCANA CORPORATION

(Exact name of registrant as specified in its charter)

 

Canada

 

98-0355077

(State or other jurisdiction of incorporation or organization)

 

(I.R.S. Employer Identification No.)

 

Suite 4400, 500 Centre Street S.E., P.O. Box 2850, Calgary, Alberta, Canada, T2P 2S5

(Address of principal executive offices)

Registrant’s telephone number, including area code (403) 645-2000

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  [X]    No  [   ]

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  [X]    No  [   ]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

 

Large accelerated filer

[X]

 

    Accelerated filer

[   ]

 

 

 

 

 

Non-accelerated  filer

[   ]

(Do not check if a smaller reporting company)

    Smaller reporting company

[   ]

 

 

 

 

 

 

 

 

    Emerging growth company

[   ]

 

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. [   ]

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  

Yes [  ]    No  [X]

 

 

 

 

 

 

Number of registrant’s common shares outstanding as of July 27, 2018

  

 

956,344,576

  

 

 

 


ENCANA CORPORATION

FORM 10-Q

TABLE OF CONTENTS

 

 

PART I

 

 

 

 

 

 

Item 1.

Financial Statements

 

6

 

Condensed Consolidated Statement of Earnings

 

6

 

Condensed Consolidated Statement of Comprehensive Income

 

6

 

Condensed Consolidated Balance Sheet

 

7

 

Condensed Consolidated Statement of Changes in Shareholders’ Equity

 

8

 

Condensed Consolidated Statement of Cash Flows

 

9

 

Notes to Condensed Consolidated Financial Statements

 

10

 

 

 

 

Item 2.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

 

37

Item 3.

Quantitative and Qualitative Disclosures about Market Risk

 

58

Item 4.

Controls and Procedures

 

59

 

 

 

 

 

PART II

 

 

 

 

 

 

Item 1.

Legal Proceedings

 

60

Item 1A.

Risk Factors

 

60

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

 

60

Item 3.

Defaults Upon Senior Securities

 

60

Item 4.

Mine Safety Disclosures

 

60

Item 5.

Other Information

 

60

Item 6.

Exhibits

 

61

Signatures

 

 

62

 

2


DEFINITIONS

Unless the context otherwise indicates, references to “us,” “we,” “our,” “ours,” “Encana” and the “Company” refer to Encana Corporation and its consolidated subsidiaries. In addition, the following are other abbreviations and definitions of certain terms used within this Quarterly Report on Form 10-Q:

“AECO” means Alberta Energy Company and is the Canadian benchmark price for natural gas.

“ASU” means Accounting Standards Update.

“bbl” or “bbls” means barrel or barrels.

“BOE” means barrels of oil equivalent.

“Btu” means British thermal units, a measure of heating value.

“DD&A” means depreciation, depletion and amortization expenses.

“FASB” means Financial Accounting Standards Board.

“Mbbls/d” means thousand barrels per day.

“MBOE/d” means thousand barrels of oil equivalent per day.

“Mcf” means thousand cubic feet.

“MD&A” means Management’s Discussion and Analysis of Financial Condition and Results of Operations.

“MMBOE” means million barrels of oil equivalent.

“MMBtu” means million Btu.

“MMcf/d” means million cubic feet per day.

“NCIB” means normal course issuer bid.

“NGL” or “NGLs” means natural gas liquids.

“NYMEX” means New York Mercantile Exchange.

“OPEC” means Organization of the Petroleum Exporting Countries.

“SEC” means United States Securities and Exchange Commission.

“TSX” means Toronto Stock Exchange.

“U.S.”, “United States” or “USA” means United States of America.

“U.S. GAAP” means U.S. Generally Accepted Accounting Principles.

“WTI” means West Texas Intermediate.

CONVERSIONS

In this Quarterly Report on Form 10-Q, a conversion of natural gas volumes to BOE is on the basis of six Mcf to one bbl.  BOE is based on a generic energy equivalency conversion method primarily applicable at the burner tip and does not represent economic value equivalency at the wellhead.  Given that the value ratio based on the current price of oil as compared to natural gas 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, particularly if used in isolation.

CONVENTIONS

Unless otherwise specified, all dollar amounts are expressed in U.S. dollars, all references to “dollars”, “$” or “US$” are to U.S. dollars and all references to “C$” are to Canadian dollars. All amounts are provided on a before tax basis, unless otherwise stated. In addition, all information provided herein is presented on an after royalties basis.

The term “liquids” is used to represent oil, NGLs and condensate. The term “liquids rich” is used to represent natural gas streams with associated liquids volumes. The term “play” is used to describe an area in which hydrocarbon accumulations or prospects of a given type occur.  Encana’s focus of development is on hydrocarbon accumulations known to exist over a large areal expanse and/or thick vertical section and are developed using hydraulic fracturing. This type of development

3


typically has a lower geological and/or commercial development risk and lower average decline rate, when compared to conventional development.

The term “core asset” refers to plays that are the focus of the Company’s current capital investment and development plan. The Company continually reviews funding for development of its plays based on strategic fit, profitability and portfolio diversity and, as such, the composition of plays identified as a core asset may change over time.

References to information contained on the Company’s website at www.encana.com are not incorporated by reference into, and does not constitute a part of, this Quarterly Report on Form 10-Q.

 

FORWARD-LOOKING STATEMENTS AND RISK

This Quarterly Report on Form 10-Q contains certain forward-looking statements or information (collectively, “forward-looking statements”) within the meaning of applicable securities legislation, including the United States Private Securities Litigation Reform Act of 1995. Forward-looking statements include: composition of the Company’s core assets, including allocation of capital and focus of development plans; growth in long-term shareholder value; vision of being a leading North American resource play company; statements with respect to the Company’s strategic objectives including capital allocation strategy, focus of investment, growth of high margin liquids volumes, operating and capital efficiencies and ability to preserve balance sheet strength; ability to lower costs and improve efficiencies to achieve competitive advantage; ability to repeat and deploy successful practices across the Company’s multi-basin portfolio; balancing commodity portfolio; anticipated commodity prices; success of and benefits from technology and innovation, including cube development approach and advanced completion designs; ability to optimize well and completion designs; future well inventory; anticipated drilling, number of drilling rigs and the success thereof; anticipated drilling costs and cycle times; anticipated proceeds and future benefits from various joint venture, partnership and other agreements; expected timing for construction of facilities and costs thereof; expansion of future midstream services; estimates of reserves and resources; expected production and product types; statements regarding anticipated cash flow, non-GAAP cash flow margin and leverage ratios; anticipated cash and cash equivalents; anticipated hedging and outcomes of risk management program, including exposure to certain commodity prices and foreign exchange, amount of hedged production, market access and physical sales locations; impact of changes in laws and regulations; compliance with environmental legislation and claims related to the purported causes and impact of climate change, and the costs therefrom; adequacy of provisions for abandonment and site reclamation costs; financial flexibility and discipline; ability to meet financial obligations, manage debt and financial ratios, finance growth and compliance with financial covenants; impact to the Company as a result of changes to its credit rating; access to the Company’s credit facilities; planned annualized dividend and the declaration and payment of future dividends, if any; the Company’s NCIB program, including amounts and number of shares to be acquired, anticipated timeframe, method and location of purchases, and source of funding thereof; adequacy of the Company’s provision for taxes and legal claims; projections and expectation of meeting the targets contained in the Company’s corporate guidance and five-year plan; ability to manage cost inflation and expected cost structures, including expected operating, transportation and processing and administrative expenses; competitiveness and pace of growth of the Company’s assets within North America and against its peers; outlook of oil and gas industry generally and impact of geopolitical environment; expected future interest expense; the Company’s commitments and obligations and anticipated payments thereunder; statements with respect to future ceiling test impairments; and the possible impact and timing of accounting pronouncements, rule changes and standards.

Readers are cautioned against unduly relying on forward-looking statements which, by their nature, involve numerous assumptions, risks and uncertainties that may cause such statements not to occur, or results to differ materially from those expressed or implied. These assumptions include: future commodity prices and differentials; foreign exchange rates; ability to access credit facilities and shelf prospectuses; assumptions contained in the Company’s corporate guidance, five-year plan and as specified herein; data contained in key modeling statistics; availability of attractive hedges and enforceability of risk management program; effectiveness of the Company’s drive to productivity and efficiencies; results from innovations; expectation that counterparties will fulfill their obligations under the gathering, midstream and marketing agreements; access to transportation and processing facilities where Encana operates; assumed tax, royalty and regulatory regimes; and expectations and projections made in light of, and generally consistent with, Encana’s historical experience and its perception of historical trends, including with respect to the pace of technological development, benefits achieved and general industry expectations.

4


Risks and uncertainties that may affect these business outcomes include: ability to generate sufficient c ash flow to meet obligations; commodity price volatility; ability to secure adequate transportation and potential pipeline curtailments; variability and discretion of Encana’s board of directors (the “Board of Directors”) to declare and pay dividends, if a ny; timing and costs of well, facilities and pipeline construction; business interruption, property and casualty losses or unexpected technical difficulties, including impact of weather; counterparty and credit risk; impact of a downgrade in credit rating and its impact on access to sources of liquidity; fluctuations in currency and interest rates; risks inherent in the Company’s corporate guidance; failure to achieve cost and efficiency initiatives; risks inherent in marketing operations; risks associated with technology; changes in or interpretation of royalty, tax, environmental, greenhouse gas, carbon, accounting and other laws or regulations; risks associated with existing and potential lawsuits and regulatory actions made against the Company; impact of disputes arising with its partners, including suspension of certain obligations and inability to dispose of assets or interests in certain arrangements; the Company’s ability to acquire or find additional reserves; imprecision of reserves estimates and es timates of recoverable quantities, including future net revenue estimates; risks associated with past and future acquisitions or divestitures of certain assets or other transactions or receipt of amounts contemplated under the transaction agreements (such transactions may include third-party capital investments, farm-outs or partnerships, which Encana may refer to from time to time as “partnerships” or “joint ventures” and the funds received in respect thereof which Encana may refer to from time to time as “proceeds”, “deferred purchase price” and/or “carry capital”, regardless of the legal form) as a result of various conditions not being met; and other risks described herein and in Item 1A. Risk Factors of the Annual Report on Form 10-K for the fiscal year ended December 31, 2017 (“2017 Annual Report on Form 10-K”) and risks and uncertainties impacting Encana's business as described from time to time in the Company's other periodic filings with the SEC.

Although the Company believes the expectations represented by such forward-looking statements are reasonable, there can be no assurance that such expectations will prove to be correct. Readers are cautioned that the assumptions, risks and uncertainties referenced above are not exhaustive. Forward-looking statements are made as of the date of this document and, except as required by law, the Company undertakes no obligation to update publicly or revise any forward-looking statements. The forward-looking statements contained in this Quarterly Report on Form 10-Q are expressly qualified by these cautionary statements.

The reader should read carefully the risk factors described herein and in Item 1A. Risk Factors of the 2017 Annual Report on Form 10-K for a description of certain risks that could, among other things, cause actual results to differ from these forward-looking statements.

 

 

 

5


 

PART I

Item 1. Financial Statements

 

Condensed Consolidated Statement of Earnings (unaudited)

 

 

 

 

 

Three Months Ended

 

 

Six Months Ended

 

 

 

 

 

June 30,

 

 

June 30,

 

(US$ millions, except per share amounts)

 

 

 

2018

 

 

2017 (1)

 

 

2018

 

 

2017 (1)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues

 

(Notes 3, 4)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Product and service revenues

 

 

 

$

1,277

 

 

$

937

 

 

$

2,537

 

 

$

1,871

 

Gains (losses) on risk management, net

 

(Note 19)

 

 

(312

)

 

 

129

 

 

 

(276

)

 

 

467

 

Sublease revenues

 

 

 

 

18

 

 

 

17

 

 

 

35

 

 

 

34

 

Total Revenues

 

 

 

 

983

 

 

 

1,083

 

 

 

2,296

 

 

 

2,372

 

Operating Expenses

 

(Note 3)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Production, mineral and other taxes

 

 

 

 

35

 

 

 

24

 

 

 

64

 

 

 

53

 

Transportation and processing

 

(Note 19)

 

 

272

 

 

 

206

 

 

 

521

 

 

 

418

 

Operating

 

(Notes 16, 17)

 

 

137

 

 

 

113

 

 

 

248

 

 

 

245

 

Purchased product

 

 

 

 

248

 

 

 

192

 

 

 

521

 

 

 

363

 

Depreciation, depletion and amortization

 

 

 

 

300

 

 

 

193

 

 

 

575

 

 

 

380

 

Accretion of asset retirement obligation

 

(Note 12)

 

 

8

 

 

 

10

 

 

 

16

 

 

 

21

 

Administrative

 

(Notes 16, 17)

 

 

99

 

 

 

24

 

 

 

130

 

 

 

82

 

Total Operating Expenses

 

 

 

 

1,099

 

 

 

762

 

 

 

2,075

 

 

 

1,562

 

Operating Income (Loss)

 

 

 

 

(116

)

 

 

321

 

 

 

221

 

 

 

810

 

Other (Income) Expenses

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest

 

(Note 5)

 

 

81

 

 

 

79

 

 

 

173

 

 

 

167

 

Foreign exchange (gain) loss, net

 

(Notes 6, 19)

 

 

25

 

 

 

(58

)

 

 

116

 

 

 

(84

)

(Gain) loss on divestitures, net

 

 

 

 

(1

)

 

 

-

 

 

 

(4

)

 

 

1

 

Other (gains) losses, net

 

(Note 17)

 

 

-

 

 

 

(27

)

 

 

(3

)

 

 

(35

)

Total Other (Income) Expenses

 

 

 

 

105

 

 

 

(6

)

 

 

282

 

 

 

49

 

Net Earnings (Loss) Before Income Tax

 

 

 

 

(221

)

 

 

327

 

 

 

(61

)

 

 

761

 

Income tax expense (recovery)

 

(Note 7)

 

 

(70

)

 

 

(4

)

 

 

(61

)

 

 

(1

)

Net Earnings (Loss)

 

 

 

$

(151

)

 

$

331

 

 

$

-

 

 

$

762

 

Net Earnings (Loss) per Common Share

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic & Diluted

 

(Note 13)

 

$

(0.16

)

 

$

0.34

 

 

$

-

 

 

$

0.78

 

Dividends Declared per Common Share

 

(Note 13)

 

$

0.015

 

 

$

0.015

 

 

$

0.03

 

 

$

0.03

 

Weighted Average Common Shares Outstanding (millions)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic & Diluted

 

(Note 13)

 

 

960.0

 

 

 

973.0

 

 

 

965.7

 

 

 

973.0

 

(1)

2017 revenues have been realigned to conform with the January 1, 2018 adoption of ASU 2014-09 “Revenue from Contracts with Customers”.

 

Condensed Consolidated Statement of Comprehensive Income (unaudited)

 

 

 

 

 

Three Months Ended

 

 

Six Months Ended

 

 

 

 

 

June 30,

 

 

June 30,

 

(US$ millions)

 

 

 

2018

 

 

2017

 

 

2018

 

 

2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net Earnings (Loss)

 

 

 

$

(151

)

 

$

331

 

 

$

-

 

 

$

762

 

Other Comprehensive Income (Loss), Net of Tax

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Foreign currency translation adjustment

 

(Note 14)

 

 

(25

)

 

 

(59

)

 

 

(1

)

 

 

(75

)

Pension and other post-employment benefit plans

 

(Notes 14, 17)

 

 

-

 

 

 

-

 

 

 

(1

)

 

 

(1

)

Other Comprehensive Income (Loss)

 

 

 

 

(25

)

 

 

(59

)

 

 

(2

)

 

 

(76

)

Comprehensive Income (Loss)

 

 

 

$

(176

)

 

$

272

 

 

$

(2

)

 

$

686

 

See accompanying Notes to Condensed Consolidated Financial Statements

 

 

6

 

 


 

Condensed Consolidated B alance Sheet (unaudited)

 

 

 

 

 

As at

 

 

As at

 

 

 

 

 

June 30,

 

 

December 31,

 

(US$ millions)

 

 

 

2018

 

 

2017

 

 

 

 

 

 

 

 

 

 

 

 

Assets

 

 

 

 

 

 

 

 

 

 

Current Assets

 

 

 

 

 

 

 

 

 

 

Cash and cash equivalents

 

 

 

$

336

 

 

$

719

 

Accounts receivable and accrued revenues

 

 

 

 

813

 

 

 

774

 

Risk management

 

(Notes 18, 19)

 

 

174

 

 

 

205

 

Income tax receivable

 

 

 

 

535

 

 

 

573

 

 

 

 

 

 

1,858

 

 

 

2,271

 

Property, Plant and Equipment, at cost:

 

(Note 9)

 

 

 

 

 

 

 

 

Oil and natural gas properties, based on full cost accounting

 

 

 

 

 

 

 

 

 

 

Proved properties

 

 

 

 

40,940

 

 

 

40,228

 

Unproved properties

 

 

 

 

4,108

 

 

 

4,480

 

Other

 

 

 

 

2,199

 

 

 

2,302

 

Property, plant and equipment

 

 

 

 

47,247

 

 

 

47,010

 

Less: Accumulated depreciation, depletion and amortization

 

 

 

 

(37,929

)

 

 

(38,056

)

Property, plant and equipment, net

 

(Note 3)

 

 

9,318

 

 

 

8,954

 

Other Assets

 

 

 

 

176

 

 

 

144

 

Risk Management

 

(Notes 18, 19)

 

 

185

 

 

 

246

 

Deferred Income Taxes

 

 

 

 

1,015

 

 

 

1,043

 

Goodwill

 

(Note 3)

 

 

2,576

 

 

 

2,609

 

 

 

(Note 3)

 

$

15,128

 

 

$

15,267

 

 

 

 

 

 

 

 

 

 

 

 

Liabilities and Shareholders’ Equity

 

 

 

 

 

 

 

 

 

 

Current Liabilities

 

 

 

 

 

 

 

 

 

 

Accounts payable and accrued liabilities

 

 

 

$

1,632

 

 

$

1,415

 

Income tax payable

 

 

 

 

4

 

 

 

7

 

Risk management

 

(Notes 18, 19)

 

 

401

 

 

 

236

 

Current portion of long-term debt

 

(Note 10)

 

 

500

 

 

 

-

 

 

 

 

 

 

2,537

 

 

 

1,658

 

Long-Term Debt

 

(Note 10)

 

 

3,698

 

 

 

4,197

 

Other Liabilities and Provisions

 

(Note 11)

 

 

1,901

 

 

 

2,167

 

Risk Management

 

(Notes 18, 19)

 

 

43

 

 

 

13

 

Asset Retirement Obligation

 

(Note 12)

 

 

420

 

 

 

470

 

Deferred Income Taxes

 

 

 

 

32

 

 

 

34

 

 

 

 

 

 

8,631

 

 

 

8,539

 

Commitments and Contingencies

 

(Note 21)

 

 

 

 

 

 

 

 

Shareholders’ Equity

 

 

 

 

 

 

 

 

 

 

Share capital - authorized unlimited common shares

 

 

 

 

 

 

 

 

 

 

2018 issued and outstanding: 956.3 million shares (2017: 973.1 million shares)

 

(Note 13)

 

 

4,674

 

 

 

4,757

 

Paid in surplus

 

 

 

 

1,358

 

 

 

1,358

 

Accumulated deficit

 

 

 

 

(575

)

 

 

(429

)

Accumulated other comprehensive income

 

(Note 14)

 

 

1,040

 

 

 

1,042

 

Total Shareholders’ Equity

 

 

 

 

6,497

 

 

 

6,728

 

 

 

 

 

$

15,128

 

 

$

15,267

 

See accompanying Notes to Condensed Consolidated Financial Statements

 

 

7

 

 


 

Condensed Consolidated Statement of Chan ges in Shareholders’ Equity (unaudited)

 

Six Months Ended June 30, 2018 (US$ millions)

 

 

 

Share

Capital

 

 

Paid in

Surplus

 

 

Accumulated

Deficit

 

 

Accumulated

Other

Comprehensive

Income

 

 

Total

Shareholders’

Equity

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance, December 31, 2017

 

 

 

$

4,757

 

 

$

1,358

 

 

$

(429

)

 

$

1,042

 

 

$

6,728

 

Net Earnings (Loss)

 

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

Dividends on Common Shares

 

(Note 13)

 

 

-

 

 

 

-

 

 

 

(29

)

 

 

-

 

 

 

(29

)

Common Shares Purchased under Normal

    Course Issuer Bid

 

(Note 13)

 

 

(83

)

 

 

-

 

 

 

(117

)

 

 

-

 

 

 

(200

)

Common Shares Issued Under

    Dividend Reinvestment Plan

 

(Note 13)

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

Other Comprehensive Income (Loss)

 

(Note 14)

 

 

-

 

 

 

-

 

 

 

-

 

 

 

(2

)

 

 

(2

)

Balance, June 30, 2018

 

 

 

$

4,674

 

 

$

1,358

 

 

$

(575

)

 

$

1,040

 

 

$

6,497

 

 

Six Months Ended June 30, 2017 (US$ millions)

 

 

 

Share

Capital

 

 

Paid in

Surplus

 

 

Accumulated

Deficit

 

 

Accumulated

Other

Comprehensive

Income

 

 

Total

Shareholders’

Equity

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance, December 31, 2016

 

 

 

$

4,756

 

 

$

1,358

 

 

$

(1,198

)

 

$

1,210

 

 

$

6,126

 

Net Earnings (Loss)

 

 

 

 

-

 

 

 

-

 

 

 

762

 

 

 

-

 

 

 

762

 

Dividends on Common Shares

 

(Note 13)

 

 

-

 

 

 

-

 

 

 

(29

)

 

 

-

 

 

 

(29

)

Common Shares Issued Under

    Dividend Reinvestment Plan

 

(Note 13)

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

Other Comprehensive Income (Loss)

 

(Note 14)

 

 

-

 

 

 

-

 

 

 

-

 

 

 

(76

)

 

 

(76

)

Balance, June 30, 2017

 

 

 

$

4,756

 

 

$

1,358

 

 

$

(465

)

 

$

1,134

 

 

$

6,783

 

See accompanying Notes to Condensed Consolidated Financial Statements

 

 

8

 

 


 

Condensed Consolidated Stateme nt of Cash Flows (unaudited)

 

 

 

 

 

Three Months Ended

 

 

Six Months Ended

 

 

 

 

 

June 30,

 

 

June 30,

 

(US$ millions)

 

 

 

2018

 

 

2017

 

 

2018

 

 

2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating Activities

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net earnings (loss)

 

 

 

$

(151

)

 

$

331

 

 

$

-

 

 

$

762

 

Depreciation, depletion and amortization

 

 

 

 

300

 

 

 

193

 

 

 

575

 

 

 

380

 

Accretion of asset retirement obligation

 

(Note 12)

 

 

8

 

 

 

10

 

 

 

16

 

 

 

21

 

Deferred income taxes

 

(Note 7)

 

 

(6

)

 

 

14

 

 

 

-

 

 

 

56

 

Unrealized (gain) loss on risk management

 

(Note 19)

 

 

326

 

 

 

(110

)

 

 

258

 

 

 

(472

)

Unrealized foreign exchange (gain) loss

 

(Note 6)

 

 

29

 

 

 

(63

)

 

 

179

 

 

 

(99

)

Foreign exchange on settlements

 

(Note 6)

 

 

4

 

 

 

7

 

 

 

(46

)

 

 

9

 

(Gain) loss on divestitures, net

 

 

 

 

(1

)

 

 

-

 

 

 

(4

)

 

 

1

 

Other

 

 

 

 

77

 

 

 

(31

)

 

 

8

 

 

 

(29

)

Net change in other assets and liabilities

 

 

 

 

(5

)

 

 

(4

)

 

 

(16

)

 

 

(16

)

Net change in non-cash working capital

 

(Note 20)

 

 

(106

)

 

 

(129

)

 

 

(114

)

 

 

(289

)

Cash From (Used in) Operating Activities

 

 

 

 

475

 

 

 

218

 

 

 

856

 

 

 

324

 

Investing Activities

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Capital expenditures

 

(Note 3)

 

 

(595

)

 

 

(415

)

 

 

(1,103

)

 

 

(814

)

Acquisitions

 

(Note 8)

 

 

-

 

 

 

(2

)

 

 

(2

)

 

 

(48

)

Proceeds from divestitures

 

(Note 8)

 

 

46

 

 

 

82

 

 

 

65

 

 

 

85

 

Net change in investments and other

 

 

 

 

105

 

 

 

24

 

 

 

80

 

 

 

79

 

Cash From (Used in) Investing Activities

 

 

 

 

(444

)

 

 

(311

)

 

 

(960

)

 

 

(698

)

Financing Activities

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Purchase of common shares

 

(Note 13)

 

 

(89

)

 

 

-

 

 

 

(200

)

 

 

-

 

Dividends on common shares

 

(Note 13)

 

 

(14

)

 

 

(14

)

 

 

(29

)

 

 

(29

)

Capital lease payments and other financing arrangements

 

(Note 11)

 

 

(23

)

 

 

(24

)

 

 

(45

)

 

 

(40

)

Cash From (Used in) Financing Activities

 

 

 

 

(126

)

 

 

(38

)

 

 

(274

)

 

 

(69

)

Foreign Exchange Gain (Loss) on Cash and Cash

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equivalents Held in Foreign Currency

 

 

 

 

(2

)

 

 

3

 

 

 

(5

)

 

 

4

 

Increase (Decrease) in Cash and Cash Equivalents

 

 

 

 

(97

)

 

 

(128

)

 

 

(383

)

 

 

(439

)

Cash and Cash Equivalents, Beginning of Period

 

 

 

 

433

 

 

 

523

 

 

 

719

 

 

 

834

 

Cash and Cash Equivalents, End of Period

 

 

 

$

336

 

 

$

395

 

 

$

336

 

 

$

395

 

Cash, End of Period

 

 

 

$

24

 

 

$

112

 

 

$

24

 

 

$

112

 

Cash Equivalents, End of Period

 

 

 

 

312

 

 

 

283

 

 

 

312

 

 

 

283

 

Cash and Cash Equivalents, End of Period

 

 

 

$

336

 

 

$

395

 

 

$

336

 

 

$

395

 

See accompanying Notes to Condensed Consolidated Financial Statements

 

 

 

 

9

 

 


 

1.

Basis of Presentation and Principles of Consolidation

Encana is in the business of the exploration for, the development of, and the production and marketing of oil, NGLs and natural gas.

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 oil and natural gas 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 are prepared in conformity with U.S. GAAP and the rules and regulations of the SEC. Pursuant to these rules and regulations, certain information and disclosures normally required under U.S. GAAP 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, 2017, which are included in Item 8 of Encana’s 2017 Annual Report on Form 10-K.

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, 2017, except as noted below in Note 2. The disclosures provided below are incremental to those included with the annual audited Consolidated Financial Statements.

These unaudited interim Condensed Consolidated Financial Statements reflect, in the opinion of Management, all normal and recurring adjustments, with the exception of an out-of-period adjustment for the three and six months ended June 30, 2017 as described in Note 6, which are 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.

. Recent Accounting Pronouncements

2.

Recent Accounting Pronouncements

Changes in Accounting Policies and Practices

On January 1, 2018, Encana adopted the following ASUs issued by the FASB, which have not had a material impact on the Company's interim Condensed Consolidated Financial Statements:

 

ASU 2014-09, “Revenue from Contracts with Customers” under Topic 606. The new standard replaces Topic 605, “Revenue Recognition” as well as other industry-specific guidance within the Accounting Standards Codification. Topic 606 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 has been applied using the modified retrospective approach and did not have a material impact on the Company’s Condensed Consolidated Financial Statements, other than enhancing disclosures related to the disaggregation of revenues from contracts with customers and performance obligations. The disclosures required under Topic 606 are included in Note 4, Revenues from Contracts with Customers.

 

ASU 2017-07, “Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost”. The amendment requires the service cost component to be presented with the related employee compensation costs, while the other components of net benefit costs are required to be presented separately from the service cost component and outside the subtotal of income from operations. In addition, the amendment allows only the service cost to be eligible for capitalization. The amendment has been applied retrospectively for the presentation of net periodic pension costs and net periodic postretirement benefit cost, whereas prospective adoption has been applied to the capitalization of the service cost component.

 

 

10

 

 


 

New Standards Issued Not Yet Adopted

As of January 1, 2019, Encana will be required to adopt ASU 2016-02, “Leases” under Topic 842, which will replace Topic 840 “Leases”. The new standard will require lessees to recognize right-of-use assets and related lease liabilities for all leases, including leases classified as operating leases, on the Consolidated Balance Sheet. The dual classification model was retained for the purpose of subsequent measurement and presentation of leases in the Consolidated Statement of Earnings and Consolidated Statement of Cash Flows. Topic 842 also expands disclosures related to the amount, timing and uncertainty of cash flows arising from leases. The standard will be applied using a modified retrospective approach and provides for certain practical expedients at the date of adoption. In January 2018, FASB issued ASU 2018-01, “Land Easement Practical Expedient for Transition to Topic 842”, which permits entities to elect an optional transition practical expedient for land easements that were not previously accounted for as leases under Topic 840. The expedient provides prospective application of Topic 842 to all new or modified land easements upon adoption of the new standard. Encana intends to elect this transitional practical expedient. Topic 842 also allows a short-term lease exemption which does not require a right-of-use asset and lease liability to be recognized on the Consolidated Balance Sheet when the lease term is 12 months or less, including any renewal periods which are reasonably certain to be exercised. Encana intends to elect the short-term lease exemption.

Encana continues to review and analyze contracts, identify its portfolio of leased assets, gather the necessary terms and data elements, as well as identify the processes and controls required to support the accounting for leases and related disclosures.   The Company is in the process of implementing a lease software system which will facilitate the measurement and required disclosures for operating leases. The Company anticipates the software implementation to be complete by the end of 2018. Although Encana is not able to reasonably estimate the financial impact of Topic 842 at this time, the Company anticipates there will be an increase in right of use assets and lease liabilities on the Consolidated Financial Statements.

As of January 1, 2019, Encana will be required to adopt ASU 2018-02 “Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income”. The amendments allow for a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Cuts and Jobs Act (“U.S. Tax Reform”). Amendments can be applied either in the period of adoption or retrospectively to each period in which the effect of the rate change from the U.S. Tax Reform is recognized. While Encana has other post-employment benefit plans which were affected by the U.S. Tax Reform, the impact is not material to the Company’s Consolidated Financial Statements. As a result, the Company does not intend to take the election provided in the amendment.

As of January 1, 2020, Encana will be required to adopt ASU 2017-04, “Simplifying the Test for Goodwill Impairment”. The amendment eliminates the second step of the goodwill impairment test which requires the Company to measure the impairment based on the excess amount of the carrying value of the reporting unit’s goodwill over the implied fair value of its goodwill. Under this amendment, the goodwill impairment will be measured based on the excess amount of the reporting unit’s carrying value over its respective fair value. The amendment will be applied prospectively at the date of adoption. Encana is currently in the early stages of reviewing the amendment, but does not expect the amendment to have a material impact on the Company’s Consolidated Financial Statements.

 

 

 

11

 

 


 

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 oil, NGLs and natural gas and other related activities within the Canadian cost centre.    

USA Operations includes the exploration for, development of, and production of oil, NGLs and natural gas 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 and cost mitigation 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. Corporate and Other also includes amounts related to sublease rentals.

 

 

12

 

 


 

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

Segment and Geographic Information

 

 

 

Canadian Operations

 

 

USA Operations

 

 

Market Optimization

 

 

 

2018

 

 

2017 (1)

 

 

2018

 

 

2017 (1)

 

 

2018

 

 

2017 (1)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Product and service revenues

 

$

379

 

 

$

265

 

 

$

607

 

 

$

468

 

 

$

291

 

 

$

204

 

Gains (losses) on risk management, net

 

 

73

 

 

 

2

 

 

 

(57

)

 

 

17

 

 

 

(2

)

 

 

-

 

Sublease revenues

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

Total Revenues

 

 

452

 

 

 

267

 

 

 

550

 

 

 

485

 

 

 

289

 

 

 

204

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating Expenses

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Production, mineral and other taxes

 

 

4

 

 

 

5

 

 

 

31

 

 

 

19

 

 

 

-

 

 

 

-

 

Transportation and processing

 

 

207

 

 

 

133

 

 

 

31

 

 

 

51

 

 

 

34

 

 

 

22

 

Operating

 

 

35

 

 

 

22

 

 

 

84

 

 

 

84

 

 

 

13

 

 

 

3

 

Purchased product

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

248

 

 

 

192

 

Depreciation, depletion and amortization

 

 

85

 

 

 

53

 

 

 

202

 

 

 

123

 

 

 

1

 

 

 

-

 

Total Operating Expenses

 

 

331

 

 

 

213

 

 

 

348

 

 

 

277

 

 

 

296

 

 

 

217

 

Operating Income (Loss)

 

$

121

 

 

$

54

 

 

$

202

 

 

$

208

 

 

$

(7

)

 

$

(13

)

 

 

 

 

 

 

 

Corporate & Other

 

 

Consolidated

 

 

 

 

 

 

 

2018

 

 

2017 (1)

 

 

2018

 

 

2017 (1)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Product and service revenues

 

 

 

 

 

$

-

 

 

$

-

 

 

$

1,277

 

 

$

937

 

Gains (losses) on risk management, net

 

 

 

 

 

 

(326

)

 

 

110

 

 

 

(312

)

 

 

129

 

Sublease revenues

 

 

 

 

 

 

18

 

 

 

17

 

 

 

18

 

 

 

17

 

Total Revenues

 

 

 

 

 

 

(308

)

 

 

127

 

 

 

983

 

 

 

1,083

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating Expenses

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Production, mineral and other taxes

 

 

 

 

 

 

-

 

 

 

-

 

 

 

35

 

 

 

24

 

Transportation and processing

 

 

 

 

 

 

-

 

 

 

-

 

 

 

272

 

 

 

206

 

Operating

 

 

 

 

 

 

5

 

 

 

4

 

 

 

137

 

 

 

113

 

Purchased product

 

 

 

 

 

 

-

 

 

 

-

 

 

 

248

 

 

 

192

 

Depreciation, depletion and amortization

 

 

 

 

 

 

12

 

 

 

17

 

 

 

300

 

 

 

193

 

Accretion of asset retirement obligation

 

 

 

 

 

 

8

 

 

 

10

 

 

 

8

 

 

 

10

 

Administrative

 

 

 

 

 

 

99

 

 

 

24

 

 

 

99

 

 

 

24

 

Total Operating Expenses

 

 

 

 

 

 

124

 

 

 

55

 

 

 

1,099

 

 

 

762

 

Operating Income (Loss)

 

 

 

 

 

$

(432

)

 

$

72

 

 

 

(116

)

 

 

321

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Other (Income) Expenses

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest

 

 

 

 

 

 

 

 

 

 

 

 

 

 

81

 

 

 

79

 

Foreign exchange (gain) loss, net

 

 

 

 

 

 

 

 

 

 

 

 

 

 

25

 

 

 

(58

)

(Gain) loss on divestitures, net

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(1

)

 

 

-

 

Other (gains) losses, net

 

 

 

 

 

 

 

 

 

 

 

 

 

 

-

 

 

 

(27

)

Total Other (Income) Expenses

 

 

 

 

 

 

 

 

 

 

 

 

 

 

105

 

 

 

(6

)

Net Earnings (Loss) Before Income Tax

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(221

)

 

 

327

 

Income tax expense (recovery)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(70

)

 

 

(4

)

Net Earnings (Loss)

 

 

 

 

 

 

 

 

 

 

 

 

 

$

(151

)

 

$

331

 

(1)

2017 revenues have been realigned to conform with the January 1, 2018 adoption of ASU 2014-09 “Revenue from Contracts with Customers”.

 

 

13

 

 


 

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

Segment and Geographic Information

 

 

 

Canadian Operations

 

 

USA Operations

 

 

Market Optimization

 

 

 

2018

 

 

2017 (1)

 

 

2018

 

 

2017 (1)

 

 

2018

 

 

2017 (1)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Product and service revenues

 

$

783

 

 

$

566

 

 

$

1,162

 

 

$

915

 

 

$

592

 

 

$

390

 

Gains (losses) on risk management, net

 

 

85

 

 

 

(19

)

 

 

(101

)

 

 

14

 

 

 

(2

)

 

 

-

 

Sublease revenues

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

Total Revenues

 

 

868

 

 

 

547

 

 

 

1,061

 

 

 

929

 

 

 

590

 

 

 

390

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating Expenses

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Production, mineral and other taxes

 

 

8

 

 

 

10

 

 

 

56

 

 

 

43

 

 

 

-

 

 

 

-

 

Transportation and processing

 

 

397

 

 

 

265

 

 

 

58

 

 

 

110

 

 

 

66

 

 

 

43

 

Operating

 

 

64

 

 

 

53

 

 

 

158

 

 

 

171

 

 

 

17

 

 

 

12

 

Purchased product

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

521

 

 

 

363

 

Depreciation, depletion and amortization

 

 

162

 

 

 

117

 

 

 

387

 

 

 

229

 

 

 

1

 

 

 

-

 

Total Operating Expenses

 

 

631

 

 

 

445

 

 

 

659

 

 

 

553

 

 

 

605

 

 

 

418

 

Operating Income (Loss)

 

$

237

 

 

$

102

 

 

$

402

 

 

$

376

 

 

$

(15

)

 

$

(28

)

 

 

 

 

 

 

 

Corporate & Other

 

 

Consolidated

 

 

 

 

 

 

 

2018

 

 

2017 (1)

 

 

2018

 

 

2017 (1)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Product and service revenues

 

 

 

 

 

$

-

 

 

$

-

 

 

$

2,537

 

 

$

1,871

 

Gains (losses) on risk management, net

 

 

 

 

 

 

(258

)

 

 

472

 

 

 

(276

)

 

 

467

 

Sublease revenues

 

 

 

 

 

 

35

 

 

 

34

 

 

 

35

 

 

 

34

 

Total Revenues

 

 

 

 

 

 

(223

)

 

 

506

 

 

 

2,296

 

 

 

2,372

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating Expenses

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Production, mineral and other taxes

 

 

 

 

 

 

-

 

 

 

-

 

 

 

64

 

 

 

53

 

Transportation and processing

 

 

 

 

 

 

-

 

 

 

-

 

 

 

521

 

 

 

418

 

Operating

 

 

 

 

 

 

9

 

 

 

9

 

 

 

248

 

 

 

245

 

Purchased product

 

 

 

 

 

 

-

 

 

 

-

 

 

 

521

 

 

 

363

 

Depreciation, depletion and amortization

 

 

 

 

 

 

25

 

 

 

34

 

 

 

575

 

 

 

380

 

Accretion of asset retirement obligation

 

 

 

 

 

 

16

 

 

 

21

 

 

 

16

 

 

 

21

 

Administrative

 

 

 

 

 

 

130

 

 

 

82

 

 

 

130

 

 

 

82

 

Total Operating Expenses

 

 

 

 

 

 

180

 

 

 

146

 

 

 

2,075

 

 

 

1,562

 

Operating Income (Loss)

 

 

 

 

 

$

(403

)

 

$

360

 

 

 

221

 

 

 

810

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Other (Income) Expenses

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest

 

 

 

 

 

 

 

 

 

 

 

 

 

 

173

 

 

 

167

 

Foreign exchange (gain) loss, net

 

 

 

 

 

 

 

 

 

 

 

 

 

 

116

 

 

 

(84

)

(Gain) loss on divestitures, net

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(4

)

 

 

1

 

Other (gains) losses, net

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(3

)

 

 

(35

)

Total Other (Income) Expenses

 

 

 

 

 

 

 

 

 

 

 

 

 

 

282

 

 

 

49

 

Net Earnings (Loss) Before Income Tax

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(61

)

 

 

761

 

Income tax expense (recovery)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(61

)

 

 

(1

)

Net Earnings (Loss)

 

 

 

 

 

 

 

 

 

 

 

 

 

$

-

 

 

$

762

 

(1)

2017 revenues have been realigned to conform with the January 1, 2018 adoption of ASU 2014-09 “Revenue from Contracts with Customers”.

 

 

14

 

 


 

Intersegment Information

 

 

 

 

 

 

 

 

 

 

 

Market Optimization

 

 

 

 

 

 

 

 

 

 

 

Marketing Sales

 

 

Upstream Eliminations

 

 

Total

 

For the three months ended June 30,

 

2018

 

 

2017

 

 

2018

 

 

2017

 

 

2018

 

 

2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues

 

$

1,359

 

 

$

951

 

 

$

(1,070

)

 

$

(747

)

 

$

289

 

 

$

204

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating Expenses

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Transportation and processing

 

 

109

 

 

 

61

 

 

 

(75

)

 

 

(39

)

 

 

34

 

 

 

22

 

Operating

 

 

13

 

 

 

3

 

 

 

-

 

 

 

-

 

 

 

13

 

 

 

3

 

Purchased product

 

 

1,243

 

 

 

900

 

 

 

(995

)

 

 

(708

)

 

 

248

 

 

 

192

 

Depreciation, depletion and amortization

 

 

1

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

1

 

 

 

-

 

Operating Income (Loss)

 

$

(7

)

 

$

(13

)

 

$

-

 

 

$

-

 

 

$

(7

)

 

$

(13

)

 

 

 

Market Optimization

 

 

 

Marketing Sales

 

 

Upstream Eliminations

 

 

Total

 

For the six months ended June 30,

 

2018

 

 

2017

 

 

2018

 

 

2017

 

 

2018

 

 

2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues

 

$

2,690

 

 

$

1,907

 

 

$

(2,100

)

 

$

(1,517

)

 

$

590

 

 

$

390

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating Expenses

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Transportation and processing

 

 

215

 

 

 

125

 

 

 

(149

)

 

 

(82

)

 

 

66

 

 

 

43

 

Operating

 

 

17

 

 

 

12

 

 

 

-

 

 

 

-

 

 

 

17

 

 

 

12

 

Purchased product

 

 

2,472

 

 

 

1,798

 

 

 

(1,951

)

 

 

(1,435

)

 

 

521

 

 

 

363

 

Depreciation, depletion and amortization

 

 

1

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

1

 

 

 

-

 

Operating Income (Loss)

 

$

(15

)

 

$

(28

)

 

$

-

 

 

$

-

 

 

$

(15

)

 

$

(28

)

 

Capital Expenditures

 

 

 

 

 

 

 

Three Months Ended

 

 

Six Months Ended

 

 

 

 

 

 

 

June 30,

 

 

June 30,

 

 

 

 

 

 

 

2018

 

 

2017

 

 

2018

 

 

2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Canadian Operations

 

 

 

 

 

$

211

 

 

$

81

 

 

$

379

 

 

$

169

 

USA Operations

 

 

 

 

 

 

382

 

 

 

333

 

 

 

720

 

 

 

644

 

Corporate & Other

 

 

 

 

 

 

2

 

 

 

1

 

 

 

4

 

 

 

1

 

 

 

 

 

 

 

$

595

 

 

$

415

 

 

$

1,103

 

 

$

814

 

 

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

 

 

 

Goodwill

 

 

Property, Plant and Equipment

 

 

Total Assets

 

 

 

As at

 

 

As at

 

 

As at

 

 

 

June 30,

 

 

December 31,

 

 

June 30,

 

 

December 31,

 

 

June 30,

 

 

December 31,

 

 

 

2018

 

 

2017

 

 

2018

 

 

2017

 

 

2018

 

 

2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Canadian Operations

 

$

663

 

 

$

696

 

 

$

981

 

 

$

862

 

 

$

1,970

 

 

$

1,908

 

USA Operations

 

 

1,913

 

 

 

1,913

 

 

 

6,889

 

 

 

6,555

 

 

 

9,596

 

 

 

9,301

 

Market Optimization

 

 

-

 

 

 

-

 

 

 

1

 

 

 

2

 

 

 

211

 

 

 

152

 

Corporate & Other

 

 

-

 

 

 

-

 

 

 

1,447

 

 

 

1,535

 

 

 

3,351

 

 

 

3,906

 

 

 

$

2,576

 

 

$

2,609

 

 

$

9,318

 

 

$

8,954

 

 

$

15,128

 

 

$

15,267

 

 

 

 

15

 

 


 

4.

Revenues from Contracts with Customers

The following tables summarize the Company’s revenues from contracts with customers and other sources of revenues. Encana presents realized and unrealized gains and losses on certain derivative contracts within revenues.

Revenues (For the three months ended June 30)

 

 

 

Canadian Operations

 

 

USA Operations

 

 

Market Optimization

 

 

 

2018

 

 

2017

 

 

2018

 

 

2017

 

 

2018

 

 

2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues from Customers

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Product revenues (1)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil

 

$

2

 

 

$

1

 

 

$

516

 

 

$

324

 

 

$

28

 

 

$

51

 

NGLs

 

 

216

 

 

 

98

 

 

 

71

 

 

 

38

 

 

 

3

 

 

 

-

 

Natural gas

 

 

164

 

 

 

169

 

 

 

29

 

 

 

103

 

 

 

246

 

 

 

149

 

Service revenues

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gathering and processing

 

 

2

 

 

 

-

 

 

 

-

 

 

 

4

 

 

 

-

 

 

 

-

 

Product and Service Revenues

 

 

384

 

 

 

268

 

 

 

616

 

 

 

469

 

 

 

277

 

 

 

200

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Other Revenues

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gains (losses) on risk management, net (2)

 

 

73

 

 

 

2

 

 

 

(57

)

 

 

17

 

 

 

(2

)

 

 

-

 

Sublease revenues

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

Other Revenues

 

 

73

 

 

 

2

 

 

 

(57

)

 

 

17

 

 

 

(2

)

 

 

-

 

Total Revenues

 

$

457

 

 

$

270

 

 

$

559

 

 

$

486

 

 

$

275

 

 

$

200

 

 

 

 

 

 

 

 

Corporate & Other

 

 

Consolidated

 

 

 

 

 

 

 

2018

 

 

2017

 

 

2018

 

 

2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues from Customers

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Product revenues (1)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil

 

 

 

 

 

$

-

 

 

$

-

 

 

$

546

 

 

$

376

 

NGLs

 

 

 

 

 

 

-

 

 

 

-

 

 

 

290

 

 

 

136

 

Natural gas

 

 

 

 

 

 

-

 

 

 

-

 

 

 

439

 

 

 

421

 

Service revenues

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gathering and processing

 

 

 

 

 

 

-

 

 

 

-

 

 

 

2

 

 

 

4

 

Product and Service Revenues

 

 

 

 

 

 

-

 

 

 

-

 

 

 

1,277

 

 

 

937

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Other Revenues

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gains (losses) on risk management, net (2)

 

 

 

 

 

 

(326

)

 

 

110

 

 

 

(312

)

 

 

129

 

Sublease revenues

 

 

 

 

 

 

18

 

 

 

17

 

 

 

18

 

 

 

17

 

Other Revenues

 

 

 

 

 

 

(308

)

 

 

127

 

 

 

(294

)

 

 

146

 

Total Revenues

 

 

 

 

 

$

(308

)

 

$

127

 

 

$

983

 

 

$

1,083

 

 

(1)

Includes revenues from production and revenues of product purchased from third parties, but excludes intercompany marketing fees transacted between the Company’s operating segments.

(2)

Canadian Operations, USA Operations and Market Optimization include realized gains/(losses) on risk management. Corporate & Other includes unrealized gains/(losses) on risk management.

 

 

 

16

 

 


 

Revenues (For t he six months ended June 30)

 

 

 

Canadian Operations

 

 

USA Operations

 

 

Market Optimization

 

 

 

2018

 

 

2017

 

 

2018

 

 

2017

 

 

2018

 

 

2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues from Customers

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Product revenues (1)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil

 

$

5

 

 

$

3

 

 

$

989

 

 

$

625

 

 

$

50

 

 

$

88

 

NGLs

 

 

396

 

 

 

193

 

 

 

123

 

 

 

78

 

 

 

5

 

 

 

12

 

Natural gas

 

 

385

 

 

 

372

 

 

 

61

 

 

 

210

 

 

 

519

 

 

 

276

 

Service revenues

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gathering and processing

 

 

4

 

 

 

4

 

 

 

-

 

 

 

10

 

 

 

-

 

 

 

-

 

Product and Service Revenues

 

 

790

 

 

 

572

 

 

 

1,173

 

 

 

923

 

 

 

574

 

 

 

376

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Other Revenues

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gains (losses) on risk management, net (2)

 

 

85

 

 

 

(19

)

 

 

(101

)

 

 

14

 

 

 

(2

)

 

 

-

 

Sublease revenues

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

Other Revenues

 

 

85

 

 

 

(19

)

 

 

(101

)

 

 

14

 

 

 

(2

)

 

 

-

 

Total Revenues

 

$

875

 

 

$

553

 

 

$

1,072

 

 

$

937

 

 

$

572

 

 

$

376

 

 

 

 

 

 

 

 

Corporate & Other

 

 

Consolidated

 

 

 

 

 

 

 

2018

 

 

2017

 

 

2018

 

 

2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues from Customers

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Product revenues (1)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil

 

 

 

 

 

$

-

 

 

$

-

 

 

$

1,044

 

 

$

716

 

NGLs

 

 

 

 

 

 

-

 

 

 

-

 

 

 

524

 

 

 

283

 

Natural gas

 

 

 

 

 

 

-

 

 

 

-

 

 

 

965

 

 

 

858

 

Service revenues

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gathering and processing

 

 

 

 

 

 

-

 

 

 

-

 

 

 

4

 

 

 

14

 

Product and Service Revenues

 

 

 

 

 

 

-

 

 

 

-

 

 

 

2,537

 

 

 

1,871

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Other Revenues

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gains (losses) on risk management, net (2)

 

 

 

 

 

 

(258

)

 

 

472

 

 

 

(276

)

 

 

467

 

Sublease revenues

 

 

 

 

 

 

35

 

 

 

34

 

 

 

35

 

 

 

34

 

Other Revenues

 

 

 

 

 

 

(223

)

 

 

506

 

 

 

(241

)

 

 

501

 

Total Revenues

 

 

 

 

 

$

(223

)

 

$

506

 

 

$

2,296

 

 

$

2,372

 

 

(1)

Includes revenues from production and revenues of product purchased from third parties, but excludes intercompany marketing fees transacted between the Company’s operating segments.

(2)

Canadian Operations, USA Operations and Market Optimization include realized gains/(losses) on risk management. Corporate & Other includes unrealized gains/(losses) on risk management.

The Company’s revenues from contracts with customers consists of product sales including oil, NGLs and natural gas, as well as the provision of gathering and processing services to third parties. Encana had no contract asset or liability balances during the periods presented. As at June 30, 2018, receivables and accrued revenues from contracts with customers were $715 million ($676 million as at December 31, 2017).

Performance obligations arising from product sales contracts are typically satisfied at a point in time when the product is delivered to the customer and control is transferred. Payment from the customer is due when the product is delivered to the custody point. The Company’s product sales are sold under short-term contracts with terms that are less than one year at either fixed or market index prices or under long-term contracts exceeding one year at market index prices.  

As at June 30, 2018, all remaining performance obligations are priced at market index prices or are variable volume delivery contracts. As such, the variable consideration is allocated entirely to the wholly unsatisfied performance obligation or promise to deliver units of production, and revenue is recognized at the amount for which the Company has the right to invoice the product delivered.

Performance obligations arising from arrangements to gather and process natural gas on behalf of third parties are typically satisfied over time as the service is provided to the customer. Payment from the customer is due when the customer receives the benefit of the service and the product is delivered to the custody point or plant tailgate. The Company’s gathering and processing services are provided on an interruptible basis with transaction prices that are for fixed prices and/or variable

 

 

17

 

 


 

consideration. Va riable consideration received is related to recovery of plant operating costs or escalation of the fixed price based on a consumer price index. As the service contracts are interruptible, with service provided on an “as available” basis, there are no unsat isfied performance obligations remaining at June 30, 2018.

 

 

5.

Interest

 

 

 

Three Months Ended

 

 

Six Months Ended

 

 

 

June 30,

 

 

June 30,

 

 

 

2018

 

 

2017

 

 

2018

 

 

2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest Expense on:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Debt

 

$

67

 

 

$

67

 

 

$

133

 

 

$

133

 

The Bow office building

 

 

16

 

 

 

15

 

 

 

32

 

 

 

31

 

Capital leases

 

 

4

 

 

 

5

 

 

 

9

 

 

 

10

 

Other

 

 

(6

)

 

 

(8

)

 

 

(1

)

 

 

(7

)

 

 

$

81

 

 

$

79

 

 

$

173

 

 

$

167

 

 

For the three and six months ended June 30, 2018, other includes $11 million of interest recovered due to the resolution of certain tax items relating to prior taxation years (2017 - $13 million and $17 million, respectively).

 

 

6.

Foreign Exchange (Gain) Loss, Net

 

 

 

Three Months Ended

 

 

Six Months Ended

 

 

 

June 30,

 

 

June 30,

 

 

 

2018

 

 

2017

 

 

2018

 

 

2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Unrealized Foreign Exchange (Gain) Loss on:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Translation of U.S. dollar financing debt issued from Canada

 

$

90

 

 

$

(45

)

 

$

212

 

 

$

(78

)

Translation of U.S. dollar risk management contracts issued from Canada

 

 

1

 

 

 

(28

)

 

 

10

 

 

 

(32

)

Translation of intercompany notes

 

 

(62

)

 

 

10

 

 

 

(43

)

 

 

11

 

 

 

 

29

 

 

 

(63

)

 

 

179

 

 

 

(99

)

Foreign Exchange on Settlements of:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

U.S. dollar financing debt issued from Canada

 

 

1

 

 

 

7

 

 

 

1

 

 

 

7

 

U.S. dollar risk management contracts issued from Canada

 

 

(3

)

 

 

2

 

 

 

(10

)

 

 

1

 

Intercompany notes

 

 

3

 

 

 

-

 

 

 

(47

)

 

 

2

 

Other Monetary Revaluations

 

 

(5

)

 

 

(4

)

 

 

(7

)

 

 

5

 

 

 

$

25

 

 

$

(58

)

 

$

116

 

 

$

(84

)

 

The unrealized foreign exchange (gain) loss on translation of U.S. dollar financing debt issued from Canada for the three and six months ended June 30, 2017 disclosed in the table above included an out-of-period adjustment in respect of unrealized losses on a foreign-denominated capital lease obligation since December 2013. The cumulative impact recognized within foreign exchange (gain) loss in the Company’s Condensed Consolidated Statement of Earnings for the three and six months ended June 30, 2017 was $68 million, before tax ($47 million, after tax). Encana determined that the adjustment was not material to the Condensed Consolidated Financial Statements for the period ended June 30, 2017 or any prior periods.

 

 

 

18

 

 


 

7.

Income Taxes

 

 

 

Three Months Ended

 

 

Six Months Ended

 

 

 

June 30,

 

 

June 30,

 

 

 

2018

 

 

2017

 

 

2018

 

 

2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current Tax

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Canada

 

$

(66

)

 

$

(20

)

 

$

(66

)

 

$

(62

)

United States

 

 

1

 

 

 

1

 

 

 

2

 

 

 

1

 

Other Countries

 

 

1

 

 

 

1

 

 

 

3

 

 

 

4

 

Total Current Tax Expense (Recovery)

 

 

(64

)

 

 

(18

)

 

 

(61

)

 

 

(57

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Deferred Tax

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Canada

 

 

(25

)

 

 

2

 

 

 

(28

)

 

 

20

 

United States

 

 

3

 

 

 

6

 

 

 

7

 

 

 

21

 

Other Countries

 

 

16

 

 

 

6

 

 

 

21

 

 

 

15

 

Total Deferred Tax Expense (Recovery)

 

 

(6

)

 

 

14

 

 

 

-

 

 

 

56

 

Income Tax Expense (Recovery)

 

$

(70

)

 

$

(4

)

 

$

(61

)

 

$

(1

)

Effective Tax Rate

 

31.7%

 

 

 

(1.2

%)

 

100.0%

 

 

 

(0.1

%)

 

Encana’s interim income tax expense is determined using the estimated annual effective income tax rate applied to year-to-date net earnings before income tax plus the effect of legislative changes and amounts in respect of prior periods. The estimated annual effective income tax rate is impacted by expected annual earnings, income tax related to foreign operations, the effect of legislative changes including U.S. Tax Reform, non-taxable capital gains and losses, tax differences on divestitures and transactions, and partnership tax allocations in excess of funding.

During the three and six months ended June 30, 2018, the current income tax recovery was primarily due to the resolution of certain tax items relating to prior taxation years. During the three and six months ended June 30, 2017, the current income tax recovery was primarily due to the successful resolution of certain tax items previously assessed by the taxing authorities relating to prior taxation years.

The effective tax rate of 100 percent for the six months ended June 30, 2018 is higher than the Canadian statutory rate of 27 percent primarily due to the current year items discussed above. The effective tax rate of (0.1) percent for the six months ended June 30, 2017 is lower than the Canadian statutory rate of 27 percent primarily due to the impact of the foreign jurisdictional tax rates relative to the Canadian statutory tax rate applied to jurisdictional earnings as well as the items discussed above.

During the six months ended June 30, 2018, there was no change to the provisional tax adjustment recognized in 2017 resulting from the re-measurement of the Company’s tax position due to a reduction of the U.S. federal corporate tax rate under U.S. Tax Reform. The provisional amount recognized may change due to additional regulatory guidance that may be issued, and from additional analysis or changes in interpretation and assumptions of the U.S. Tax Reform made by the Company.

 

 

 

 

19

 

 


 

8.

Acquisitions and Divestitures

 

 

 

Three Months Ended

 

 

Six Months Ended

 

 

 

June 30,

 

 

June 30,

 

 

 

2018

 

 

2017

 

 

2018

 

 

2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Acquisitions

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Canadian Operations

 

$

-

 

 

$

-

 

 

$

2

 

 

$

31

 

USA Operations

 

 

-

 

 

 

2

 

 

 

-

 

 

 

17

 

Total Acquisitions

 

 

-

 

 

 

2

 

 

 

2

 

 

 

48

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Divestitures

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Canadian Operations

 

 

(44

)

 

 

(3

)

 

 

(57

)

 

 

(6

)

USA Operations

 

 

(2

)

 

 

(79

)

 

 

(8

)

 

 

(79

)

Total Divestitures

 

 

(46

)

 

 

(82

)

 

 

(65

)

 

 

(85

)

Net Acquisitions & (Divestitures)

 

$

(46

)

 

$

(80

)

 

$

(63

)

 

$

(37

)

Acquisitions

For the six months ended June 30, 2018, acquisitions in the Canadian and USA Operations were $2 million (2017 - $31 million) and nil (2017 - $17 million), respectively, which primarily included land purchases with oil and liquids rich potential.

Divestitures

For the six months ended June 30, 2018, divestitures in the Canadian Operations were $57 million, which primarily included the sale of the Pipestone midstream assets located in Alberta. During the six months ended June 30, 2017, divestitures in the Canadian Operations were $6 million, which primarily included the sale of certain properties that did not complement Encana’s existing portfolio of assets.

For the six months ended June 30, 2018, divestitures in the USA Operations were $8 million, which primarily included the sale of certain properties that did not complement Encana’s existing portfolio of assets. During the six months ended June 30, 2017, divestitures in the USA Operations were $79 million, which primarily included the sale of the Tuscaloosa Marine Shale assets in Mississippi and Louisiana.

Amounts received from the Company’s divestiture transactions have been deducted from the respective Canadian and U.S. full cost pools.

 

 

 

 

20

 

 


 

9.

Property, Plant and Equipment, Net

 

 

 

As at June 30, 2018

 

 

As at December 31, 2017

 

 

 

 

 

 

 

Accumulated

 

 

 

 

 

 

 

 

 

 

Accumulated

 

 

 

 

 

 

 

Cost

 

 

DD&A

 

 

Net

 

 

Cost

 

 

DD&A

 

 

Net

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Canadian Operations

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proved properties

 

$

14,246

 

 

$

(13,540

)

 

$

706

 

 

$

14,555

 

 

$

(14,047

)

 

$

508

 

Unproved properties

 

 

243

 

 

 

-

 

 

 

243

 

 

 

311

 

 

 

-

 

 

 

311

 

Other

 

 

32

 

 

 

-

 

 

 

32

 

 

 

43

 

 

 

-

 

 

 

43

 

 

 

 

14,521

 

 

 

(13,540

)

 

 

981

 

 

 

14,909

 

 

 

(14,047

)

 

 

862

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

USA Operations

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proved properties

 

 

26,635

 

 

 

(23,627

)

 

 

3,008

 

 

 

25,610

 

 

 

(23,240

)

 

 

2,370

 

Unproved properties

 

 

3,865

 

 

 

-

 

 

 

3,865

 

 

 

4,169

 

 

 

-

 

 

 

4,169

 

Other

 

 

16

 

 

 

-

 

 

 

16

 

 

 

16

 

 

 

-

 

 

 

16

 

 

 

 

30,516

 

 

 

(23,627

)

 

 

6,889

 

 

 

29,795

 

 

 

(23,240

)

 

 

6,555

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Market Optimization

 

 

7

 

 

 

(6

)

 

 

1

 

 

 

7

 

 

 

(5

)

 

 

2

 

Corporate & Other

 

 

2,203

 

 

 

(756

)

 

 

1,447

 

 

 

2,299

 

 

 

(764

)

 

 

1,535

 

 

 

$

47,247

 

 

$

(37,929

)

 

$

9,318

 

 

$

47,010

 

 

$

(38,056

)

 

$

8,954

 

 

Canadian and USA Operations property, plant and equipment include internal costs directly related to exploration, development and construction activities of $109 million, which have been capitalized during the six months ended June 30, 2018 (2017 - $77 million). Included in Corporate and Other are $59 million ($63 million as at December 31, 2017) of international property costs, which have been fully impaired.

Capital Lease Arrangements

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

As at June 30, 2018, the total carrying value of assets under capital lease was $44 million ($46 million as at December 31, 2017), net of accumulated amortization of $664 million ($684 million as at December 31, 2017). 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.

Other Arrangement

As at June 30, 2018, Corporate and Other property, plant and equipment and total assets include a carrying value of $1,185 million ($1,255 million as at December 31, 2017) 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.

 

 

 

 

21

 

 


 

10.

Long-Term Debt

 

 

 

As at

 

 

As at

 

 

 

June 30,

 

 

December 31,

 

 

 

2018

 

 

2017

 

 

 

 

 

 

 

 

 

 

U.S. Dollar Denominated Debt

 

 

 

 

 

 

 

 

U.S. Unsecured Notes:

 

 

 

 

 

 

 

 

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

 

 

462

 

 

 

462

 

6.50% due February 1, 2038

 

 

505

 

 

 

505

 

5.15% due November 15, 2041

 

 

244

 

 

 

244

 

Total Principal

 

 

4,211

 

 

 

4,211

 

 

 

 

 

 

 

 

 

 

Increase in Value of Debt Acquired

 

 

24

 

 

 

26

 

Unamortized Debt Discounts and Issuance Costs

 

 

(37

)

 

 

(40

)

Current Portion of Long-Term Debt

 

 

(500

)

 

 

-

 

 

 

$

3,698

 

 

$

4,197

 

 

As at June 30, 2018, total long-term debt had a carrying value of $4,198 million and a fair value of $4,792 million (as at December 31, 2017 - carrying value of $4,197 million and a fair value of $5,042 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 of long-term debt with similar terms and maturity, or by discounting future payments of interest and principal at interest rates expected to be available to the Company at period end.

 

 

11.

Other Liabilities and Provisions

 

 

 

As at

 

 

As at

 

 

 

June 30,

 

 

December 31,

 

 

 

2018

 

 

2017

 

 

 

 

 

 

 

 

 

 

The Bow Office Building

 

$

1,274

 

 

$

1,344

 

Capital Lease Obligations

 

 

254

 

 

 

295

 

Unrecognized Tax Benefits

 

 

169

 

 

 

202

 

Pensions and Other Post-Employment Benefits

 

 

118

 

 

 

116

 

Long-Term Incentive Costs (See Note 16)

 

 

52

 

 

 

175

 

Other Derivative Contracts (See Notes 18, 19)

 

 

12

 

 

 

14

 

Other

 

 

22

 

 

 

21

 

 

 

$

1,901

 

 

$

2,167

 

 

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 lease term, the remaining asset and corresponding liability are expected to be derecognized. Encana has also subleased approximately 50 percent of The Bow office space under the lease agreement. The total expected future principal and interest payments related to the 25-year lease agreement and the total undiscounted future amounts expected to be recovered from the sublease are outlined below.

 

 

 

22

 

 


 

 

 

2018

 

 

2019

 

 

2020

 

 

2021

 

 

2022

 

 

Thereafter

 

 

Total

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Expected Future Lease Payments

 

$

36

 

 

$

73

 

 

$

74

 

 

$

74

 

 

$

75

 

 

$

1,233

 

 

$

1,565

 

Less: Amounts Representing Interest

 

 

31

 

 

 

61

 

 

 

61

 

 

 

60

 

 

 

59

 

 

 

763

 

 

 

1,035

 

Present Value of Expected Future

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Lease Payments

 

$

5

 

 

$

12

 

 

$

13

 

 

$

14

 

 

$

16

 

 

$

470

 

 

$

530

 

Sublease Recoveries (undiscounted)

 

$

(18

)

 

$

(36

)

 

$

(36

)

 

$

(36

)

 

$

(37

)

 

$

(607

)

 

$

(770

)

 

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 and the Deep Panuke offshore Production Field Centre (“PFC”). 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.

 

 

 

2018

 

 

2019

 

 

2020

 

 

2021

 

 

2022

 

 

Thereafter

 

 

Total

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Expected Future Lease Payments

 

$

50

 

 

$

99

 

 

$

99

 

 

$

87

 

 

$

8

 

 

$

38

 

 

$

381

 

Less: Amounts Representing Interest

 

 

9

 

 

 

15

 

 

 

10

 

 

 

4

 

 

 

2

 

 

 

5

 

 

 

45

 

Present Value of Expected Future

   Lease Payments

 

$

41

 

 

$

84

 

 

$

89

 

 

$

83

 

 

$

6

 

 

$

33

 

 

$

336

 

 

 

12.

Asset Retirement Obligation

 

 

 

As at

 

 

As at

 

 

 

June 30,

 

 

December 31,

 

 

 

2018

 

 

2017

 

 

 

 

 

 

 

 

 

 

Asset Retirement Obligation, Beginning of Year

 

$

514

 

 

$

687

 

Liabilities Incurred and Acquired

 

 

10

 

 

 

11

 

Liabilities Settled and Divested

 

 

(15

)

 

 

(333

)

Change in Estimated Future Cash Outflows

 

 

-

 

 

 

88

 

Accretion Expense

 

 

16

 

 

 

37

 

Foreign Currency Translation

 

 

(19

)

 

 

24

 

Asset Retirement Obligation, End of Period

 

$

506

 

 

$

514

 

 

 

 

 

 

 

 

 

 

Current Portion

 

$

86

 

 

$

44

 

Long-Term Portion

 

 

420

 

 

 

470

 

 

 

$

506

 

 

$

514

 

 

 

 

 

23

 

 


 

13.

Share Capital

Authorized

The Company is authorized to issue an unlimited number of no par value common shares and Class A Preferred Shares limited to a number equal to not more than 20 percent of the issued and outstanding number of common shares at the time of issuance. No Class A Preferred Shares are outstanding.

Issued and Outstanding

 

 

 

As at

June 30, 2018

 

 

As at

December 31, 2017

 

 

 

Number

(millions)

 

 

Amount

 

 

Number

(millions)

 

 

Amount

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Common Shares Outstanding, Beginning of Year

 

 

973.1

 

 

$

4,757

 

 

 

973.0

 

 

$

4,756

 

Common Shares Purchased

 

 

(16.8

)

 

 

(83

)

 

 

-

 

 

 

-

 

Common Shares Issued Under Dividend Reinvestment Plan

 

 

-

 

 

 

-

 

 

 

0.1

 

 

 

1

 

Common Shares Outstanding, End of Period

 

 

956.3

 

 

$

4,674

 

 

 

973.1

 

 

$

4,757

 

 

During the six months ended June 30, 2018, Encana issued 31,212 common shares totaling $0.4 million under the Company’s dividend reinvestment plan (“DRIP”). During the twelve months ended December 31, 2017, Encana issued 58,480 common shares totaling $0.6 million under the DRIP.

Dividends

During the three months ended June 30, 2018, Encana paid dividends of $0.015 per common share totaling $14 million (2017 - $0.015 per common share totaling $14 million). During the six months ended June 30, 2018, Encana paid dividends of $0.03 per common share totaling $29 million (2017 - $0.03 per common share totaling $29 million).

For the three and six months ended June 30, 2018, the dividends paid included $0.1 million and $0.4 million, respectively, in common shares issued in lieu of cash dividends under the DRIP (for the three and six months ended June 30, 2017 - $0.1 million and $0.3 million, respectively).  

On July 31, 2018, the Board of Directors declared a dividend of $0.015 per common share payable on September 28, 2018 to common shareholders of record as of September 14, 2018.

Normal Course Issuer Bid

On February 26, 2018, the Company announced it received approval from the TSX to purchase, for cancellation, up to 35 million common shares pursuant to a NCIB over a 12-month period from February 28, 2018 to February 27, 2019. The Company has authorization from its Board to spend up to $400 million on the NCIB.

All purchases are made in accordance with the NCIB at prevailing market prices plus brokerage fees, with consideration allocated to share capital up to the average carrying amount of the shares, and any excess is allocated to retained earnings/accumulated deficit.

For the six months ended June 30, 2018, the Company purchased approximately 16.8 million common shares for total consideration of approximately $200 million. Of the amount paid, $83 million was charged to share capital and $117 million was charged to accumulated deficit.

 

 

24

 

 


 

Earnings Per Common Share

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

 

 

 

 

Three Months Ended

 

 

 

Six Months Ended

 

 

 

 

June 30,

 

 

 

June 30,

 

(US$ millions, except per share amounts)

 

 

2018

 

 

2017

 

 

 

2018

 

 

2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net Earnings (Loss)

 

 

$

(151

)

 

$

331

 

 

 

$

-

 

 

$

762

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Number of Common Shares:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Weighted average common shares outstanding - Basic

 

 

 

960.0

 

 

 

973.0

 

 

 

 

965.7

 

 

 

973.0

 

Effect of dilutive securities

 

 

 

-

 

 

 

-

 

 

 

 

-

 

 

 

-

 

Weighted average common shares outstanding - Diluted

 

 

 

960.0

 

 

 

973.0

 

 

 

 

965.7

 

 

 

973.0

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net Earnings (Loss) per Common Share

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic & Diluted

 

 

$

(0.16

)

 

$

0.34

 

 

 

$

-

 

 

$

0.78

 

 

Encana Stock Option Plan

Encana has share-based compensation plans that allow employees to purchase common shares of the Company. Option exercise prices are not less than the market value of the common shares on the date the options are granted. All options outstanding as at June 30, 2018 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, outstanding TSARs are not considered potentially dilutive securities.

Encana Restricted Share Units (“RSUs”)

 

Encana has a share-based compensation plan whereby eligible employees and Directors are granted RSUs. An RSU is a conditional grant to receive the equivalent of an Encana common share upon vesting of the RSUs and in accordance with the terms of the RSU Plan and Grant Agreement. The Company currently settles vested RSUs in cash. As a result, RSUs are not considered potentially dilutive securities.  

 

 

14.

Accumulated Other Comprehensive Income

 

 

 

Three Months Ended

 

 

Six Months Ended

 

 

 

June 30,

 

 

June 30,

 

 

 

2018

 

 

2017

 

 

2018

 

 

2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Foreign Currency Translation Adjustment

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance, Beginning of Period

 

$

1,053

 

 

$

1,184

 

 

$

1,029

 

 

$

1,200

 

Change in Foreign Currency Translation Adjustment

 

 

(25

)

 

 

(59

)

 

 

(1

)

 

 

(75

)

Balance, End of Period

 

$

1,028

 

 

$

1,125

 

 

$

1,028

 

 

$

1,125

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Pension and Other Post-Employment Benefit Plans

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance, Beginning of Period

 

$

12

 

 

$

9

 

 

$

13

 

 

$

10

 

Reclassification of Net Actuarial (Gains) and Losses to Net Earnings (See Note 17)

 

 

-

 

 

 

-

 

 

 

(1

)

 

 

(1

)

Income Taxes

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

Balance, End of Period

 

$

12

 

 

$

9

 

 

$

12

 

 

$

9

 

Total Accumulated Other Comprehensive Income

 

$

1,040

 

 

$

1,134

 

 

$

1,040

 

 

$

1,134

 

 

 

 

 

25

 

 


 

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. 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 is the expected lease payments over the initial contract term. As at June 30, 2018, Encana had a capital lease obligation of $278 million ($314 million as at December 31, 2017) related to the PFC.

Veresen Midstream Limited Partnership

Veresen Midstream Limited Partnership (“VMLP”) provides gathering, compression and processing services under various agreements related to the Company’s development of liquids and natural gas production in the Montney play. As at June 30, 2018, VMLP provides approximately 1,150 MMcf/d of natural gas gathering and compression and 887 MMcf/d of natural gas processing under long-term service agreements with remaining terms ranging from up to 13 to 27 years and have various renewal terms providing up to a potential maximum of 10 years.

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

As a result of Encana’s involvement with VMLP, the maximum total exposure, which represents the potential exposure to Encana in the event the assets under the agreements are deemed worthless, is estimated to be $2,382 million as at June 30, 2018. The estimate comprises the take or pay volume commitments and the potential payout of minimum costs. The take or pay volume commitments associated with certain gathering and processing assets are included in Note 21 under Transportation and Processing. The potential payout requirement is highly uncertain as the amount is contingent on future production estimates, pace of development and the amount of capacity contracted to third parties. As at June 30, 2018, there were no accounts payable and accrued liabilities outstanding related to the take or pay commitment.

 

 

16.

Compensation Plans

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

Encana accounts for TSARs, Performance TSARs, SARs, PSUs and RSUs held by 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.  

 

 

26

 

 


 

The following weighted average assumptions were used to determine the fair value of the share units held by employees:  

 

 

 

As at June 30, 2018

 

 

As at June 30, 2017

 

 

 

US$ Share

Units

 

C$ Share

Units

 

 

US$ Share

Units

 

C$ Share

Units

 

 

 

 

 

 

 

 

 

 

 

 

Risk Free Interest Rate

 

1.84%

 

1.84%

 

 

1.09%

 

1.09%

 

Dividend Yield

 

0.46%

 

0.45%

 

 

0.68%

 

0.70%

 

Expected Volatility Rate (1)

 

57.6%

 

54.1%

 

 

59.17%

 

54.94%

 

Expected Term

 

1.8 yrs

 

2.0 yrs

 

 

1.9 yrs

 

1.9 yrs

 

Market Share Price

 

US$13.05

 

C$17.17

 

 

US$8.80

 

C$11.41

 

(1)

Volatility was estimated using historical rates.

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

 

 

 

Three Months Ended

June 30,

 

 

Six Months Ended

June 30,

 

 

 

2018

 

 

2017

 

 

2018

 

 

2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total Compensation Costs of Transactions Classified as Cash-Settled

 

$

109

 

 

$

(41

)

 

$

82

 

 

$

(7

)

Less: Total Share-Based Compensation Costs Capitalized

 

 

(31

)

 

 

11

 

 

 

(22

)

 

 

-

 

Total Share-Based Compensation Expense (Recovery)

 

$

78

 

 

$

(30

)

 

$

60

 

 

$

(7

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Recognized on the Condensed Consolidated Statement of Earnings in:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating

 

$

22

 

 

$

(8

)

 

$

16

 

 

$

-

 

Administrative

 

 

56

 

 

 

(22

)

 

 

44

 

 

 

(7

)

 

 

$

78

 

 

$

(30

)

 

$

60

 

 

$

(7

)

 

As at June 30, 2018, the liability for share-based payment transactions totaled $319 million ($327 million as at December 31, 2017), of which $267 million ($152 million as at December 31, 2017) is recognized in accounts payable and accrued liabilities and $52 million ($175 million as at December 31, 2017) is recognized in other liabilities and provisions in the Condensed Consolidated Balance Sheet.

 

 

 

As at

June 30,

2018

 

 

As at

December 31,

2017

 

 

 

 

 

 

 

 

 

 

Liability for Cash-Settled Share-Based Payment Transactions:

 

 

 

 

 

 

 

 

Unvested

 

$

255

 

 

$

274

 

Vested

 

 

64

 

 

 

53

 

 

 

$

319

 

 

$

327

 

 

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

 

Six Months Ended June 30, 2018 (thousands of units)

 

 

 

 

 

 

 

 

 

TSARs

 

 

872

 

SARs

 

 

359

 

PSUs

 

 

2,515

 

DSUs

 

 

32

 

RSUs

 

 

5,275

 

 

 

 

 

27

 

 


 

17.

Pension and Other Post-Employment Benefits

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

 

 

 

Pension Benefits

 

 

OPEB

 

 

Total

 

 

 

2018

 

 

2017

 

 

2018

 

 

2017

 

 

2018

 

 

2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net Defined Periodic Benefit Cost

 

$

-

 

 

$

(1

)

 

$

3

 

 

$

5

 

 

$

3

 

 

$

4

 

Defined Contribution Plan Expense

 

 

12

 

 

 

12

 

 

 

-

 

 

 

-

 

 

 

12

 

 

 

12

 

Total Benefit Plans Expense

 

$

12

 

 

$

11

 

 

$

3

 

 

$

5

 

 

$

15

 

 

$

16

 

 

Of the total benefit plans expense, $11 million (2017 - $12 million) was included in operating expense and $4 million (2017 - $4 million) was included in administrative expense.

The net defined periodic benefit cost for the six months ended June 30 is as follows:

 

 

 

Defined Benefits

 

 

OPEB

 

 

Total

 

 

 

2018

 

 

2017

 

 

2018

 

 

2017

 

 

2018

 

 

2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Service Cost

 

$

-

 

 

$

-

 

 

$

3

 

 

$

4

 

 

$

3

 

 

$

4

 

Interest Cost

 

 

4

 

 

 

4

 

 

 

1

 

 

 

2

 

 

 

5

 

 

 

6

 

Expected Return on Plan Assets

 

 

(4

)

 

 

(5

)

 

 

-

 

 

 

-

 

 

 

(4

)

 

 

(5

)

Amounts Reclassified from Accumulated Other

    Comprehensive Income:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Amortization of net actuarial (gains) and losses

 

 

-

 

 

 

-

 

 

 

(1

)

 

 

(1

)

 

 

(1

)

 

 

(1

)

Total Net Defined Periodic Benefit Cost (1)

 

$

-

 

 

$

(1

)

 

$

3

 

 

$

5

 

 

$

3

 

 

$

4

 

 

(1)

The components of total net defined periodic benefit cost, excluding the service cost component, are included in other (gains) losses, net.

 

18.

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.

Recurring fair value measurements are performed for risk management assets and liabilities and other derivative contracts, as discussed further in Note 19. 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 following tables. There have been no significant transfers between the hierarchy levels during the period.

 

 

28

 

 


 

Fair value c hanges and settlements for amounts related to risk management assets and liabilities are recognized in revenues , transportation and processing expense , and foreign exchange gains and losses according to their purpose.

 

As at June 30, 2018

 

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 Assets

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity Derivatives:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current assets

 

$

7

 

 

$

293

 

 

$

-

 

 

$

300

 

 

$

(129

)

 

$

171

 

Long-term assets

 

 

-

 

 

 

198

 

 

 

-

 

 

 

198

 

 

 

(14

)

 

 

184

 

Foreign Currency Derivatives:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current assets

 

 

-

 

 

 

3

 

 

 

-

 

 

 

3

 

 

 

-

 

 

 

3

 

Long-term assets

 

 

-

 

 

 

1

 

 

 

-

 

 

 

1

 

 

 

-

 

 

 

1

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Risk Management Liabilities

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity Derivatives:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current liabilities

 

$

-

 

 

$

431

 

 

$

98

 

 

$

529

 

 

$

(129

)

 

$

400

 

Long-term liabilities

 

 

-

 

 

 

38

 

 

 

19

 

 

 

57

 

 

 

(14

)

 

 

43

 

Foreign Currency Derivatives:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current liabilities

 

 

-

 

 

 

1

 

 

 

-

 

 

 

1

 

 

 

-

 

 

 

1

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Other Derivative Contracts

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current in accounts payable and accrued liabilities

 

$

-

 

 

$

5

 

 

$

-

 

 

$

5

 

 

$

-

 

 

$

5

 

Long-term in other liabilities and provisions

 

 

-

 

 

 

12

 

 

 

-

 

 

 

12

 

 

 

-

 

 

 

12

 

 

As at December 31, 2017

 

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 Assets

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity Derivatives:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current assets

 

$

-

 

 

$

189

 

 

$

-

 

 

$

189

 

 

$

(15

)

 

$

174

 

Long-term assets

 

 

-

 

 

 

248

 

 

 

-

 

 

 

248

 

 

 

(2

)

 

 

246

 

Foreign Currency Derivatives:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current assets

 

 

-

 

 

 

31

 

 

 

-

 

 

 

31

 

 

 

-

 

 

 

31

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Risk Management Liabilities

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity Derivatives:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current liabilities

 

$

3

 

 

$

196

 

 

$

51

 

 

$

250

 

 

$

(15

)

 

$

235

 

Long-term liabilities

 

 

-

 

 

 

15

 

 

 

-

 

 

 

15

 

 

 

(2

)

 

 

13

 

Foreign Currency Derivatives:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current liabilities

 

 

-

 

 

 

1

 

 

 

-

 

 

 

1

 

 

 

-

 

 

 

1

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Other Derivative Contracts

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current in accounts payable and accrued liabilities

 

$

-

 

 

$

5

 

 

$

-

 

 

$

5

 

 

$

-

 

 

$

5

 

Long-term in other liabilities and provisions

 

 

-

 

 

 

14

 

 

 

-

 

 

 

14

 

 

 

-

 

 

 

14

 

 

(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.

The Company’s Level 1 and Level 2 risk management assets and liabilities consist of commodity fixed price contracts, fixed price swaptions, NYMEX call options, foreign currency swaps and basis swaps with terms to 2023. Level 2 also includes financial guarantee contracts as discussed in Note 19. 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.  

 

 

29

 

 


 

Level 3 Fair Value Measurements

As at June 30, 2018, the Company’s Level 3 risk management assets and liabilities consist of WTI three-way options and WTI costless collars with terms to 2019. The WTI three-way options are a combination of a sold call, bought put and a sold put. The WTI costless collars are a combination of a sold call and a bought put. These contracts allow the Company to participate in the upside of commodity prices to the ceiling of the call option and provide the Company with complete (collars) or partial (three-way) downside price protection through the put options. The fair values of the WTI three-way options and WTI costless collars are based on the income approach and are modelled using observable and unobservable inputs such as implied volatility. The unobservable inputs are obtained from third parties whenever possible and reviewed by the Company for reasonableness.

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

 

 

 

Risk Management

 

 

 

2018

 

 

2017

 

 

 

 

 

 

 

 

 

 

Balance, Beginning of Year

 

$

(51

)

 

$

(36

)

Total Gains (Losses)

 

 

(19

)

 

 

64

 

Purchases, Sales, Issuances and Settlements:

 

 

 

 

 

 

 

 

Purchases, sales and issuances

 

 

-

 

 

 

-

 

Settlements

 

 

(47

)

 

 

3

 

Transfers Out of Level 3 (1)

 

 

-

 

 

 

-

 

Balance, End of Period

 

$

(117

)

 

$

31

 

Change in Unrealized Gains (Losses) Related to

   Assets and Liabilities Held at End of Period

 

$

(93

)

 

$

59

 

 

(1)

The Company’s policy is to recognize transfers out of Level 3 on the date of the event of change in circumstances that caused the transfer.

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

 

 

 

Valuation Technique

 

Unobservable Input

 

 

As at

June 30,

2018

 

 

As at

December 31,

2017

 

Risk Management - WTI Options

 

Option Model

 

Implied Volatility

 

 

24% - 100%

 

 

17% - 76%

 

 

A 10 percent increase or decrease in implied volatility for the WTI options would cause a corresponding $7 million ($2 million as at December 31, 2017) increase or decrease to net risk management assets and liabilities.

 

 

19.

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, accounts payable and accrued liabilities, risk management assets and liabilities, long-term debt and other liabilities and provisions.

B)  Risk Management Activities

Encana uses derivative financial instruments to manage its exposure to cash flow variability from commodity prices and fluctuating foreign currency exchange rates. The Company does not apply hedge accounting to any of its derivative financial instruments. As a result, gains and losses from changes in the fair value are recognized in net earnings.

Commodity Price Risk

Commodity price risk arises from the effect that 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.  

 

 

30

 

 


 

Crude Oil and NGLs - To partially mitigate crude oil and NGL commodity price risk, the Company uses WTI-based and Mont Belvieu-based contracts such as fixed price contracts, fixed price swaptions, options and costless collars. Encana has also entered into basis swaps to manage a gainst widening price differentials between various production areas and benchmark price points.

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

Foreign Exchange Risk

Foreign exchange risk arises from changes in foreign currency exchange rates that may affect the fair value or future cash flows of the Company’s financial assets or liabilities. To partially mitigate the effect of foreign exchange fluctuations on future commodity revenues and expenses, the Company may enter into foreign currency derivative contracts. As at June 30, 2018, Encana has entered into $358 million notional U.S. dollar denominated currency swaps at an average exchange rate of US$0.7606 to C$1, which mature monthly through the remainder of 2018 and $250 million notional U.S. dollar denominated currency swaps at an average exchange rate of US$0.7581 to C$1, which mature monthly throughout 2019.

 

 

31

 

 


 

Risk Management Positions as at June 30, 2018

 

 

 

Notional Volumes

 

Term

 

Average Price

 

 

Fair Value

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude Oil and NGL Contracts

 

 

 

 

 

US$/bbl

 

 

 

 

 

Fixed Price Contracts

 

 

 

 

 

 

 

 

 

 

 

 

WTI Fixed Price

 

102.3 Mbbls/d

 

2018

 

 

55.52

 

 

$

(280

)

WTI Fixed Price

 

35.0 Mbbls/d

 

2019

 

 

60.31

 

 

 

(62

)

Propane Fixed Price

 

9.0 Mbbls/d

 

2018

 

 

39.05

 

 

 

(1

)

Butane Fixed Price

 

7.0 Mbbls/d

 

2018

 

 

43.49

 

 

 

(2

)

 

 

 

 

 

 

 

 

 

 

 

 

 

WTI Fixed Price Swaptions (1)

 

24.0 Mbbls/d

 

Q1 - Q2 2019

 

 

63.13

 

 

 

(29

)

 

 

 

 

 

 

 

 

 

 

 

 

 

WTI Three-Way Options

 

 

 

 

 

 

 

 

 

 

 

 

Sold call / bought put / sold put

 

16.0 Mbbls/d

 

2018

 

54.49 / 47.17 / 36.88

 

 

 

(46

)

Sold call / bought put / sold put

 

42.0 Mbbls/d

 

2019

 

68.38 / 59.11 / 48.21

 

 

 

(47

)

 

 

 

 

 

 

 

 

 

 

 

 

 

WTI Costless Collars

 

 

 

 

 

 

 

 

 

 

 

 

Sold call / bought put

 

10.0 Mbbls/d

 

2018

 

57.08 / 45.00

 

 

 

(24

)

 

 

 

 

 

 

 

 

 

 

 

 

 

Basis Contracts (2)

 

 

 

2018

 

 

 

 

 

 

60

 

 

 

 

 

2019 - 2020

 

 

 

 

 

 

40

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude Oil and NGLs Fair Value Position

 

 

 

 

 

 

 

 

 

 

(391

)

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural Gas Contracts

 

 

 

 

 

US$/Mcf

 

 

 

 

 

Fixed Price Contracts

 

 

 

 

 

 

 

 

 

 

 

 

NYMEX Fixed Price

 

1,084 MMcf/d

 

2018

 

 

3.02

 

 

 

14

 

NYMEX Fixed Price

 

699 MMcf/d

 

2019

 

 

2.72

 

 

 

(20

)

 

 

 

 

 

 

 

 

 

 

 

 

 

NYMEX Fixed Price Swaptions (3)

 

300 MMcf/d

 

Q1 - Q2 2019

 

 

2.99

 

 

 

(8

)

 

 

 

 

 

 

 

 

 

 

 

 

 

NYMEX Call Options

 

 

 

 

 

 

 

 

 

 

 

 

Sold call price

 

230 MMcf/d

 

2018

 

 

3.75

 

 

 

(1

)

Sold call price

 

230 MMcf/d

 

2019

 

 

3.75

 

 

 

(4

)

Bought call price

 

230 MMcf/d

 

2019

 

 

3.75

 

 

 

-

 

Sold call price

 

230 MMcf/d

 

2020

 

 

3.25

 

 

 

-

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Basis Contracts (4)

 

 

 

2018

 

 

 

 

 

 

77

 

 

 

 

 

2019

 

 

 

 

 

 

127

 

 

 

 

 

2020

 

 

 

 

 

 

94

 

 

 

 

 

2021 - 2023

 

 

 

 

 

 

28

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural Gas Fair Value Position

 

 

 

 

 

 

 

 

 

 

307

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net Premiums Received on Unexpired Options

 

 

 

 

 

 

 

 

 

 

(4

)

 

 

 

 

 

 

 

 

 

 

 

 

 

Other Derivative Contracts

 

 

 

 

 

 

 

 

 

 

 

 

Fair Value Position

 

 

 

 

 

 

 

 

 

 

(17

)

 

 

 

 

 

 

 

 

 

 

 

 

 

Foreign Currency Contracts

 

 

 

 

 

 

 

 

 

 

 

 

Fair Value Position (5)

 

 

 

2018 - 2019

 

 

 

 

 

 

3

 

Total Fair Value Position and Net Premiums Received

 

 

 

 

 

 

 

 

 

$

(102

)

 

(1 )

WTI Fixed Price Swaptions give the counterparty the option to extend certain Q3 - Q4 2018 Fixed Price swaps to Q1- Q2 2019.

(2)

Encana has entered into swaps to protect against weakening Midland, Magellan East Houston, Louisiana Light Sweet and Edmonton Condensate differentials to WTI.

(3)

NYMEX Fixed Price Swaptions give the counterparty the option to extend certain Q3 - Q4 2018 Fixed Price swaps to Q1- Q2 2019.

(4)

Encana has entered into swaps to protect against weakening AECO, Dawn, Chicago, Malin and Waha basis to NYMEX.

(5)

Encana has entered into U.S. dollar denominated fixed-for-floating average currency swaps to protect against fluctuations between the Canadian and U.S. dollars.

 

 

32

 

 


 

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

 

 

 

Three Months Ended

 

 

Six Months Ended

 

 

 

June 30,

 

 

June 30,

 

 

 

2018

 

 

2017

 

 

2018

 

 

2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Realized Gains (Losses) on Risk Management

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity and Other Derivatives:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues (1)

 

$

14

 

 

$

19

 

 

$

(18

)

 

$

(5

)

Transportation and processing

 

 

-

 

 

 

-

 

 

 

-

 

 

 

(4

)

Foreign Currency Derivatives:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Foreign exchange

 

 

3

 

 

 

(2

)

 

 

10

 

 

 

(1

)

 

 

$

17

 

 

$

17

 

 

$

(8

)

 

$

(10

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Unrealized Gains (Losses) on Risk Management

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity and Other Derivatives:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues (2)

 

$

(326

)

 

$

110

 

 

$

(258

)

 

$

472

 

Foreign Currency Derivatives:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Foreign exchange

 

 

(8

)

 

 

24

 

 

 

(26

)

 

 

26

 

 

 

$

(334

)

 

$

134

 

 

$

(284

)

 

$

498

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total Realized and Unrealized Gains (Losses) on Risk Management, net

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity and Other Derivatives:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues (1) (2)

 

$

(312

)

 

$

129

 

 

$

(276

)

 

$

467

 

Transportation and processing

 

 

-

 

 

 

-

 

 

 

-

 

 

 

(4

)

Foreign Currency Derivatives:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Foreign exchange

 

 

(5

)

 

 

22

 

 

 

(16

)

 

 

25

 

 

 

$

(317

)

 

$

151

 

 

$

(292

)

 

$

488

 

 

(1)

Includes realized gains of $2 million and $3 million for the three and six months ended June 30, 2018, respectively, (2017 - gains of $1 million and $3 million, respectively) related to other derivative contracts.

(2)

Includes unrealized losses of $1 million and $1 million for the three and six months ended June 30, 2018, respectively, (2017 - losses of $1 million and $1 million, respectively) related to other derivative contracts.

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

 

 

 

 

 

2018

 

 

2017

 

 

 

 

 

Fair Value

 

 

Total

Unrealized

Gain (Loss)

 

 

Total

Unrealized

Gain (Loss)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Fair Value of Contracts, Beginning of Year

 

 

 

$

183

 

 

 

 

 

 

 

 

 

Change in Fair Value of Contracts in Place at Beginning of Year

   and Contracts Entered into During the Period

 

 

 

 

(292

)

 

$

(292

)

 

$

488

 

Settlement of Other Derivative Contracts

 

 

 

 

3

 

 

 

 

 

 

 

 

 

Fair Value of Contracts Realized During the Period

 

 

 

 

8

 

 

 

8

 

 

 

10

 

Fair Value of Contracts Outstanding

 

 

 

$

(98

)

 

$

(284

)

 

$

498

 

Net Premiums Received on Unexpired Options

 

 

 

 

(4

)

 

 

 

 

 

 

 

 

Fair Value of Contracts and Net Premiums Received, End of Period

 

 

 

$

(102

)

 

 

 

 

 

 

 

 

 

Risk management assets and liabilities arise from the use of derivative financial instruments and are measured at fair value.  See Note 18 for a discussion of fair value measurements.

 

 

33

 

 


 

Unrealized Risk Management Positions

 

 

 

As at

 

 

As at

 

 

 

June 30,

 

 

December 31,

 

 

 

2018

 

 

2017

 

 

 

 

 

 

 

 

 

 

Risk Management Assets

 

 

 

 

 

 

 

 

Current

 

$

174

 

 

$

205

 

Long-term

 

 

185

 

 

 

246

 

 

 

 

359

 

 

 

451

 

 

 

 

 

 

 

 

 

 

Risk Management Liabilities

 

 

 

 

 

 

 

 

Current

 

 

401

 

 

 

236

 

Long-term

 

 

43

 

 

 

13

 

 

 

 

444

 

 

 

249

 

 

 

 

 

 

 

 

 

 

Other Derivative Contracts

 

 

 

 

 

 

 

 

Current in accounts payable and accrued liabilities

 

 

5

 

 

 

5

 

Long-term in other liabilities and provisions

 

 

12

 

 

 

14

 

Net Risk Management Assets (Liabilities) and Other Derivative Contracts

 

$

(102

)

 

$

183

 

 

C)  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. While exchange-traded contracts are subject to nominal credit risk due to the financial safeguards established by the New York Stock Exchange and the TSX, over-the-counter traded contracts expose Encana to counterparty credit risk. This credit risk exposure is mitigated through the use of credit policies approved by the Board of Directors 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 a result of netting provisions, the Company’s maximum exposure to loss under derivative financial instruments due to credit risk is limited to the net amounts due from the counterparties under the derivative contracts, as disclosed in Note 18. As at June 30, 2018, the Company had no significant credit derivatives in place and held no collateral.

As at June 30, 2018, 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 that have investment grade credit ratings.  

A substantial portion of the Company’s accounts receivable are with customers in the oil and gas industry and are subject to normal industry credit risks. As at June 30, 2018, approximately 92 percent (92 percent as at December 31, 2017) of Encana’s accounts receivable and financial derivative credit exposures were with investment grade counterparties.

As at June 30, 2018, Encana had two counterparties whose net settlement position individually accounted for more than 10 percent of the fair value of the outstanding in-the-money net risk management contracts by counterparty. As at June 30, 2018, these counterparties accounted for 47 percent and 11 percent of the fair value of the outstanding in-the-money net risk management contracts. As at December 31, 2017, Encana had three counterparties whose net settlement position accounted for 56 percent, 11 percent and 11 percent of the fair value of the outstanding in-the-money net risk management contracts.

During 2015 and 2017, Encana entered into agreements resulting from divestitures, which may require Encana to fulfill certain payment obligations on the take or pay volume commitments assumed by the purchasers. The circumstances that would require Encana to perform under the agreements include events where a purchaser fails to make payment to the guaranteed party and/or a purchaser is subject to an insolvency event. The agreements have remaining terms from three to six years with a fair value recognized of $17 million as at June 30, 2018 ($19 million as at December 31, 2017). The maximum potential amount of undiscounted future payments is $287 million as at June 30, 2018, and is considered unlikely.

 

 

 

34

 

 


 

 

20 .

Supplementary Information

Supplemental disclosures to the Condensed Consolidated Statement of Cash Flows are presented below:

A)

Net Change in Non-Cash Working Capital

 

 

Three Months Ended

 

 

Six Months Ended

 

 

 

June 30,

 

 

June 30,

 

 

 

2018

 

 

2017

 

 

2018

 

 

2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating Activities

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Accounts receivable and accrued revenues

 

$

(142

)

 

$

33

 

 

$

(144

)

 

$

103

 

Accounts payable and accrued liabilities

 

 

47

 

 

 

(37

)

 

 

40

 

 

 

(171

)

Income tax receivable and payable

 

 

(11

)

 

 

(125

)

 

 

(10

)

 

 

(221

)

 

 

$

(106

)

 

$

(129

)

 

$

(114

)

 

$

(289

)

 

B)

Non-Cash Activities

 

 

Three Months Ended

 

 

Six Months Ended

 

 

 

June 30,

 

 

June 30,

 

 

 

2018

 

 

2017

 

 

2018

 

 

2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Non-Cash Investing Activities

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Asset retirement obligation incurred (See Note 12)

 

$

5

 

 

$

3

 

 

$

10

 

 

$

6

 

Property, plant and equipment accruals

 

 

72

 

 

 

34

 

 

 

81

 

 

 

78

 

Capitalized long-term incentives

 

 

31

 

 

 

(11

)

 

 

(5

)

 

 

-

 

Property additions/dispositions (swaps)

 

 

91

 

 

 

159

 

 

 

140

 

 

 

165

 

Non-Cash Financing Activities

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Common shares issued under dividend reinvestment plan (See Note 13)

 

$

-

 

 

$

-

 

 

$

-

 

 

$

-

 

 

 

21.

Commitments and Contingencies

Commitments

The following table outlines the Company’s commitments as at June 30, 2018:

 

 

 

Expected Future Payments

 

(undiscounted)

 

2018

 

 

2019

 

 

2020

 

 

2021

 

 

2022

 

 

Thereafter

 

 

Total

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Transportation and Processing

 

$

294

 

 

$

692

 

 

$

669

 

 

$

582

 

 

$

555

 

 

$

2,516

 

 

$

5,308

 

Drilling and Field Services

 

 

123

 

 

 

50

 

 

 

24

 

 

 

9

 

 

 

-

 

 

 

-

 

 

 

206

 

Operating Leases

 

 

9

 

 

 

17

 

 

 

16

 

 

 

16

 

 

 

16

 

 

 

50

 

 

 

124

 

Total

 

$

426

 

 

$

759

 

 

$

709

 

 

$

607

 

 

$

571

 

 

$

2,566

 

 

$

5,638

 

 

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

 

 

35

 

 


 

Contingencies

Encana is involved in various legal claims and actions arising in the normal 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. Management’s assessment of these matters may change in the future as certain of these matters are in early stages or are subject to a number of uncertainties. For material matters that the Company believes an unfavourable outcome is reasonably possible, the Company discloses the nature and a range of potential exposures. If an unfavourable outcome were to occur, there exists the possibility of a material impact on the Company’s consolidated net earnings or loss for the period in which the effect becomes reasonably estimable. The Company accrues for such items when a liability is both probable and the amount can be reasonably estimated. Such accruals are based on the Company’s information known about the matters, estimates of the outcomes of such matters and experience in handling similar matters.

 

 

 

 

 

36

 

 


 

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations


The MD&A is intended to provide a narrative description of Encana’s business from management’s perspective. This MD&A should be read in conjunction with the unaudited interim Condensed Consolidated Financial Statements and accompanying notes for the period ended June 30, 2018 (“Consolidated Financial Statements”), which are included in Part I, Item 1 of this Quarterly Report on Form 10-Q and the audited Consolidated Financial Statements and accompanying notes and MD&A for the year ended December 31, 2017, which are included in Items 8 and 7, respectively, of the 2017 Annual Report on Form 10-K. Common industry terms and abbreviations are used throughout this MD&A and are defined in the Definitions, Conversions and Conventions sections of this Quarterly Report on Form 10-Q. This MD&A includes the following sections:

 

 

Executive Overview

 

Results of Operations

 

Liquidity and Capital Resources

 

Non-GAAP Measures

 

 

Executive Overview

Strategy

Encana is a leading North American energy producer that is focused on developing its multi-basin portfolio of oil, NGLs and natural gas producing plays. Encana is committed to growing long-term shareholder value through a disciplined focus on generating profitable growth. The Company is pursuing the key business objectives of exercising a disciplined capital allocation strategy by investing in a limited number of core assets, growing high margin liquids volumes, maximizing profitability through operating efficiencies and reducing costs, and preserving balance sheet strength.

In executing its strategy, Encana focuses on its core values of One, Agile and Driven, which guide the organization to be flexible, responsive, determined and motivated with a commitment to excellence and a passion to succeed as a unified team.

Encana continually reviews and evaluates its strategy and changing market conditions. In 2018, Encana continues to focus on quality growth from high margin, scalable projects located in some of the best plays in North America, referred to as the “Core Assets”, comprising Montney and Duvernay in Canada and Eagle Ford and Permian in the U.S. These world-class assets form a multi-basin portfolio enabling flexible and efficient investment of capital. The Company rapidly deploys successful ideas and practices across these assets, becoming more efficient as innovative and sustainable technical improvements are implemented.

For additional information on Encana’s strategy, its reporting segments and the plays in which the Company operates, refer to Items 1 and 2 of the 2017 Annual Report on Form 10-K. In evaluating its operations and assessing its leverage, the Company reviews performance-based measures such as Non-GAAP Cash Flow and Non-GAAP Cash Flow Margin and debt-based metrics such as Debt to Adjusted Capitalization and Net Debt to Adjusted EBITDA, which are non-GAAP measures and do not have any standardized meaning under U.S. GAAP. These measures may not be similar to measures presented by other issuers and should not be viewed as a substitute for measures reported under U.S. GAAP. Further information regarding these measures, including reconciliations to the closest GAAP measure, can be found in the Non-GAAP Measures section of this MD&A.


 

37


 

Highlights

During the first six months of 2018, Encana focused on executing its 2018 capital plan, maintaining operational efficiencies achieved in 2017 and minimizing the effect of inflationary costs. Higher revenues in the first six months of 2018 compared to 2017 resulting from higher liquids production volumes and benchmark prices. Liquids production volumes increased by 27 percent compared to 2017. Higher oil and NGL benchmark prices contributed to increases in Encana’s average realized oil and NGL prices of 36 percent and 31 percent, respectively. Encana is also focused on the diversification of the Company’s downstream markets to capture higher realized prices. Encana remains committed to delivering a business model that allows the Company to adapt to fluctuating commodity prices.

Significant Developments

 

Received approval from the TSX to purchase, for cancellation, up to 35 million common shares pursuant to a NCIB over a 12-month period from February 28, 2018 to February 27, 2019. As of June 30, 2018, the Company has purchased approximately 16.8 million common shares for total consideration of approximately $200 million.

 

Announced an agreement with Keyera Partnership, a subsidiary of Keyera Corp., on April 2, 2018 to sell the Company’s Pipestone liquids hub in Alberta. In conjunction with the sale, Keyera will own and construct a natural gas processing facility and provide Encana with processing services under a competitive fee-for-service arrangement in support of the Company’s liquids growth plans in Montney.

Financial Results

Three months ended June 30, 2018

 

Reported net loss of $151 million, including a net loss on risk management in revenues of $312 million, before tax, and net foreign exchange loss of $25 million, before tax.

 

Recovered current taxes of approximately $64 million and interest of $11 million primarily resulting from the resolution of certain tax items relating to prior taxation years .

 

Generated cash from operating activities of $475 million, Non-GAAP Cash Flow of $586 million and Non-GAAP Cash Flow Margin of $19.09 per BOE, including the tax items noted above.

 

Paid dividends of $0.015 per common share.

Six months ended June 30, 2018

 

Reported net earnings of nil, including a net loss on risk management in revenues of $276 million, before tax, and net foreign exchange loss of $116 million, before tax.

 

Recovered current taxes of approximately $61 million and interest of $11 million primarily resulting from the resolution of certain tax items relating to prior taxation years .

 

Generated cash from operating activities of $856 million, Non-GAAP Cash Flow of $986 million and Non-GAAP Cash Flow Margin of $16.46 per BOE, including the tax items noted above.

 

Paid dividends of $0.03 per common share.

 

Held cash and cash equivalents of $336 million and had available credit facilities of $4.0 billion for total liquidity of $4.3 billion at June 30, 2018.

Capital Investment

 

Directed $420 million, or 71 percent, of total capital spending in Permian and Montney in the second quarter of 2018 and $813 million, or 74 percent, during the first six months of 2018.

 

Focused on highly efficient capital activity and short-cycle high margin projects providing flexibility to respond to fluctuations in commodity prices.

 

38


 

Production

Three months ended June 30, 2018

 

Produced average oil and NGL volumes of 155.3 Mbbls/d which accounted for 46 percent of total production volumes. Average oil and plant condensate production volumes of 118.3 Mbbls/d were 76 percent of total liquids production volumes.

 

Produced average natural gas volumes of 1,095 MMcf/d which accounted for 54 percent of total production volumes.

Six months ended June 30, 2018

 

Produced average oil and NGL volumes of 150.3 Mbbls/d which accounted for 45 percent of total production volumes. Average oil and plant condensate production volumes of 115.7 Mbbls/d were 77 percent of total liquids production volumes.

 

Produced average natural gas volumes of 1,085 MMcf/d which accounted for 55 percent of total production volumes.

Revenues and Operating Expenses

 

Focused on market diversification to other downstream markets to maximize realized commodity prices and revenues through a combination of derivative financial instruments and transportation contracts.

 

Secured pipeline transportation capacity to the Dawn and Houston markets to protect against weakening AECO and Midland differentials to NYMEX and WTI, respectively; maintained access to local markets through existing transportation contracts.

 

Preserved operational efficiencies achieved in previous years and minimized the effect of inflationary costs.

 

Incurred higher transportation and processing expense in the second quarter and the first six months of 2018 of $66 million, or 32 percent, and $103 million, or 25 percent, respectively, compared to the same periods in 2017 primarily due to higher volumes in Montney and additional costs incurred in conjunction with the diversification of other downstream markets to capture higher realized prices.

 

2018 Outlook

Industry Outlook

The oil and gas industry is cyclical and commodity prices are inherently volatile. Oil prices during 2018 are expected to reflect global supply and demand dynamics as well as the geopolitical environment. The original OPEC agreement implemented in 2017 to limit output and the drawdowns of oil storage inventory levels were generally supportive of oil prices in the first half of 2018. At a meeting in June 2018, OPEC and certain non-OPEC countries agreed to increase future oil production, which could negatively impact prices for the remainder of the year. Conversely, oil supply outages resulting from geopolitical instability in major producing countries could positively impact prices for the remainder of the year.

Natural gas prices in 2018 will be affected by the timing of supply and demand growth. Natural gas prices in western Canada have seen significant negative price pressure as supply reached multi-year highs, surpassing regional demand and stressing effective pipeline capacity. Stronger condensate prices may also lend support to activity levels resulting in continued downward pressure on natural gas prices in the second half of 2018. Potential for improvement in U.S. natural gas prices remains limited due to continued substantial production increases in Northeast U.S. and associated gas production in the Permian Basin.

Company Outlook

Encana is positioned to be flexible in the current price environment in order to continue to achieve strong returns. The Company enters into derivative financial instruments which mitigate price volatility and help sustain revenues during periods of lower prices. A portion of the Company’s production is sold at prevailing market prices which also allows Encana to

 

39


 

participate in potential price increases. As at June 30, 2018, the Company has hedged approximately 128 Mbbls/d of expected oil and condensate production and 1,0 84 MMcf/d of expected natural gas production for the remainder of 2018 . A dditional information on Encana’s hedging program can be found in Note 19 to the Consolidated Financial Statements included in Part I, Item 1 of this Quarterly Report on Form 10-Q.

Markets for crude oil and natural gas are exposed to different price risks. While the market price for crude oil tends to move in the same direction as the global market, the Permian Basin is experiencing wider differentials due to temporary local export capacity constraints. Natural gas prices may vary between geographic regions depending on local supply and demand conditions. Encana proactively utilizes transportation contracts to diversify the Company’s downstream markets and reduce significant exposure to any given market. Through a combination of derivative financial instruments and transportation capacity, Encana has mitigated the majority of its exposure to Midland and AECO pricing in 2018 and 2019. In addition, Encana continues to seek new markets to yield higher returns.

Capital Investment

Encana is on track to meet its full year capital investment guidance of $1.8 billion to $1.9 billion. During the first six months of 2018, the Company spent $1.1 billion, of which $488 million was directed to Permian where the Company has drilled 55 net wells and $325 million was directed to Montney with 81 net wells drilled. Capital investment in Permian is expected to be optimized by Encana’s cube development approach to maximize returns and recovery. Capital investment in Montney is expected to be allocated to both Cutbank Ridge and Pipestone with a focus on growing condensate volumes. The remainder of the capital investment was primarily directed to Eagle Ford and Duvernay and is expected to optimize production and margins.

Encana continually strives to improve well performance by lowering drilling and completion costs through innovative techniques. Encana's large-scale cube development model utilizes multi-well pads and advanced completion designs to access stacked pay resource to maximize returns and resource recovery from its reservoirs. The impact of Encana’s disciplined capital program and continuous innovation create flexibility and opportunity to grow cash flows and production volumes going forward.

Production

As part of the Company’s long-term growth strategy, Encana has significantly shifted its production mix to a more balanced portfolio in the recent years, thereby reducing the extent of exposure to market volatility of a particular commodity. During the first six months of 2018, average liquids production volumes were 150.3 Mbbls/d and average natural gas production volumes were 1,085 MMcf/d. The Company expects to deliver substantial liquids growth for the remainder of the year. The Company is on track to meet the full year 2018 guidance ranges for liquids production volumes of 165.0 Mbbls/d to 175.0 Mbbls/d and natural gas production volumes of 1,150 MMcf/d to 1,250 MMcf/d by year end as a result of the Company’s growth plans for Montney. Encana’s growth plans for Montney are supported by third party processing plants commissioned in 2017 and the second quarter of 2018, as well as the planned completion of the Pipestone liquids hub in the second half of 2018.

Operating Expenses

Efficiency improvements and lower service costs are expected to be maintained through the support of the Company’s culture of innovation and its focus on continuous improvement in operational execution. As activity in the industry accelerates, Encana expects to continue pursuing innovative ways to reduce upstream operating and administrative expenses. Operating costs in the first six months of 2018 are on track to meet the full year 2018 guidance ranges. Transportation and processing expense was $7.58 per BOE, while upstream operating expense and administrative expense, excluding long-term incentive costs, were $3.50 per BOE and $1.43 per BOE, respectively.

Service costs are expected to increase with higher activity in the oil and gas industry and the recovery of liquids prices. Encana continues to offset any inflationary pressures with efficiency improvements and effective supply chain management, including favorable price negotiations.

Further information on Encana’s 2018 Corporate Guidance can be accessed on the Company’s website at www.encana.com .

 

40


 

Results of Operations

Selected Financial Information

 

 

 

Three months ended June 30,

 

 

 

 

Six months ended June 30,

 

($ millions)

 

 

2018

 

 

2017 (1)

 

 

 

 

2018

 

 

2017 (1)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Product and Service Revenues

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Upstream product revenues

 

 

$

984

 

 

$

729

 

 

 

 

$

1,941

 

 

$

1,467

 

Market optimization

 

 

 

291

 

 

 

204

 

 

 

 

 

592

 

 

 

390

 

Service revenues

 

 

 

2

 

 

 

4

 

 

 

 

 

4

 

 

 

14

 

Total Product and Service Revenues

 

 

 

1,277

 

 

 

937

 

 

 

 

 

2,537

 

 

 

1,871

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gains (Losses) on Risk Management, Net

 

 

 

(312

)

 

 

129

 

 

 

 

 

(276

)

 

 

467

 

Sublease Revenues

 

 

 

18

 

 

 

17

 

 

 

 

 

35

 

 

 

34

 

Total Revenues

 

 

 

983

 

 

 

1,083

 

 

 

 

 

2,296

 

 

 

2,372

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total Operating Expenses (2)

 

 

 

1,099

 

 

 

762

 

 

 

 

 

2,075

 

 

 

1,562

 

Operating Income (Loss)

 

 

 

(116

)

 

 

321

 

 

 

 

 

221

 

 

 

810

 

Total Other (Income) Expenses

 

 

 

105

 

 

 

(6

)

 

 

 

 

282

 

 

 

49

 

Net Earnings (Loss) Before Income Tax

 

 

 

(221

)

 

 

327

 

 

 

 

 

(61

)

 

 

761

 

Income Tax Expense (Recovery)

 

 

 

(70

)

 

 

(4

)

 

 

 

 

(61

)

 

 

(1

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net Earnings (Loss)

 

 

$

(151

)

 

$

331

 

 

 

 

$

-

 

 

$

762

 

 

(1)

2017 revenues have been realigned to conform with the January 1, 2018 adoption of ASU 2014-09 “Revenue from Contracts with Customers”, as described in Note 2 to the Consolidated Financial Statements included in Part I, Item 1 of this Quarterly Report on Form 10-Q.

(2)

Total Operating Expenses include non-cash items such as DD&A, impairments, accretion of asset retirement obligations and long-term incentive costs.

Revenues

Encana’s revenues are substantially derived from sales of oil, NGLs and natural gas production. Increases or decreases in Encana’s revenue, profitability and future production are highly dependent on the commodity prices the Company receives. Prices are market driven and fluctuate due to factors beyond the Company’s control, such as supply and demand, seasonality and geopolitical and economic factors. Canadian Operations realized prices are linked to Edmonton Condensate and AECO, as well as other downstream natural gas benchmarks, including Dawn. The USA Operations realized prices generally reflect WTI and NYMEX benchmark prices, as well as other downstream oil benchmarks. The other downstream benchmarks reflect the diversification of the Company’s markets. Realized NGL prices are significantly influenced by oil benchmark prices and the NGL production mix. Recent trends in benchmark prices relevant to Encana are shown in the table below.

Benchmark Prices

 

 

 

Three months ended June 30,

 

 

 

 

Six months ended June 30,

 

(average for the period)

 

 

2018

 

 

2017

 

 

 

 

2018

 

 

2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil & NGLs

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

WTI ($/bbl)

 

 

$

67.88

 

 

$

48.29

 

 

 

 

$

65.37

 

 

$

50.10

 

Edmonton Condensate (C$/bbl)

 

 

$

88.84

 

 

$

64.59

 

 

 

 

$

84.28

 

 

$

66.87

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural Gas

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

NYMEX ($/MMBtu)

 

 

$

2.80

 

 

$

3.18

 

 

 

 

$

2.90

 

 

$

3.25

 

AECO (C$/Mcf)

 

 

$

1.03

 

 

$

2.77

 

 

 

 

$

1.44

 

 

$

2.86

 

Dawn (C$/MMBtu)

 

 

$

3.60

 

 

$

4.17

 

 

 

 

$

3.71

 

 

$

4.20

 

 

 

41


 

Production Volumes and Realized Price s

 

 

Three months ended June 30,

 

 

 

 

Six months ended June 30,

 

 

 

Production Volumes (1)

 

 

 

Realized Prices (2)

 

 

 

 

Production Volumes (1)

 

 

 

Realized Prices (2)

 

 

 

2018

 

 

 

2017

 

 

 

2018

 

 

2017

 

 

 

 

2018

 

 

 

2017

 

 

 

2018

 

 

2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil (Mbbls/d, $/bbl)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Canadian Operations

 

 

0.4

 

 

 

 

0.4

 

 

 

$

58.13

 

 

$

40.23

 

 

 

 

 

0.4

 

 

 

 

0.4

 

 

 

$

56.87

 

 

$

41.77

 

USA Operations

 

 

84.2

 

 

 

 

77.0

 

 

 

 

66.57

 

 

 

46.14

 

 

 

 

 

83.4

 

 

 

 

72.0

 

 

 

 

64.97

 

 

 

47.75

 

Total

 

 

84.6

 

 

 

 

77.4

 

 

 

 

66.52

 

 

 

46.11

 

 

 

 

 

83.8

 

 

 

 

72.4

 

 

 

 

64.93

 

 

 

47.72

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

NGLs – Plant Condensate (Mbbls/d, $/bbl)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Canadian Operations

 

 

29.9

 

 

 

 

20.5

 

 

 

 

67.55

 

 

 

46.94

 

 

 

 

 

28.7

 

 

 

 

19.6

 

 

 

 

64.48

 

 

 

48.53

 

USA Operations

 

 

3.8

 

 

 

 

2.3

 

 

 

 

57.20

 

 

 

41.07

 

 

 

 

 

3.2

 

 

 

 

2.1

 

 

 

 

55.05

 

 

 

41.86

 

Total

 

 

33.7

 

 

 

 

22.8

 

 

 

 

66.38

 

 

 

46.34

 

 

 

 

 

31.9

 

 

 

 

21.7

 

 

 

 

63.51

 

 

 

47.89

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

NGLs – Other (Mbbls/d, $/bbl)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Canadian Operations

 

 

12.5

 

 

 

 

4.7

 

 

 

 

26.27

 

 

 

19.10

 

 

 

 

 

11.5

 

 

 

 

4.9

 

 

 

 

27.99

 

 

 

20.91

 

USA Operations

 

 

24.5

 

 

 

 

20.0

 

 

 

 

22.37

 

 

 

16.06

 

 

 

 

 

23.1

 

 

 

 

19.0

 

 

 

 

21.51

 

 

 

17.97

 

Total

 

 

37.0

 

 

 

 

24.7

 

 

 

 

23.69

 

 

 

16.65

 

 

 

 

 

34.6

 

 

 

 

23.9

 

 

 

 

23.66

 

 

 

18.57

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total NGLs (Mbbls/d, $/bbl)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Canadian Operations

 

 

42.4

 

 

 

 

25.2

 

 

 

 

55.35

 

 

 

41.73

 

 

 

 

 

40.2

 

 

 

 

24.5

 

 

 

 

54.03

 

 

 

43.01

 

USA Operations

 

 

28.3

 

 

 

 

22.3

 

 

 

 

27.08

 

 

 

18.68

 

 

 

 

 

26.3

 

 

 

 

21.1

 

 

 

 

25.67

 

 

 

20.34

 

Total

 

 

70.7

 

 

 

 

47.5

 

 

 

 

44.01

 

 

 

30.93

 

 

 

 

 

66.5

 

 

 

 

45.6

 

 

 

 

42.79

 

 

 

32.54

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total Oil & NGLs (Mbbls/d, $/bbl)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Canadian Operations

 

 

42.8

 

 

 

 

25.6

 

 

 

 

55.38

 

 

 

41.71

 

 

 

 

 

40.6

 

 

 

 

24.9

 

 

 

 

54.06

 

 

 

43.00

 

USA Operations

 

 

112.5

 

 

 

 

99.3

 

 

 

 

56.61

 

 

 

40.00

 

 

 

 

 

109.7

 

 

 

 

93.1

 

 

 

 

55.53

 

 

 

41.55

 

Total

 

 

155.3

 

 

 

 

124.9

 

 

 

 

56.27

 

 

 

40.35

 

 

 

 

 

150.3

 

 

 

 

118.0

 

 

 

 

55.14

 

 

 

41.86

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural Gas (MMcf/d, $/Mcf)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Canadian Operations

 

 

949

 

 

 

 

785

 

 

 

 

1.84

 

 

 

2.33

 

 

 

 

 

942

 

 

 

 

835

 

 

 

 

2.16

 

 

 

2.43

 

USA Operations

 

 

146

 

 

 

 

361

 

 

 

 

2.07

 

 

 

3.09

 

 

 

 

 

143

 

 

 

 

359

 

 

 

 

2.29

 

 

 

3.16

 

Total

 

 

1,095

 

 

 

 

1,146

 

 

 

 

1.87

 

 

 

2.57

 

 

 

 

 

1,085

 

 

 

 

1,194

 

 

 

 

2.17

 

 

 

2.65

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total Production (MBOE/d, $/BOE)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Canadian Operations

 

 

200.9

 

 

 

 

156.6

 

 

 

 

20.50

 

 

 

18.52

 

 

 

 

 

197.6

 

 

 

 

164.1

 

 

 

 

21.37

 

 

 

18.89

 

USA Operations

 

 

137.0

 

 

 

 

159.4

 

 

 

 

48.72

 

 

 

31.92

 

 

 

 

 

133.6

 

 

 

 

152.8

 

 

 

 

48.08

 

 

 

32.71

 

Total

 

 

337.9

 

 

 

 

316.0

 

 

 

 

31.93

 

 

 

25.29

 

 

 

 

 

331.2

 

 

 

 

316.9

 

 

 

 

32.14

 

 

 

25.55

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Production Mix (%)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil & Plant Condensate

 

 

35

 

 

 

 

32

 

 

 

 

 

 

 

 

 

 

 

 

 

 

35

 

 

 

 

30

 

 

 

 

 

 

 

 

 

 

NGLs – Other

 

 

11

 

 

 

 

8

 

 

 

 

 

 

 

 

 

 

 

 

 

 

10

 

 

 

 

7

 

 

 

 

 

 

 

 

 

 

Total Oil & NGLs

 

 

46

 

 

 

 

40

 

 

 

 

 

 

 

 

 

 

 

 

 

 

45

 

 

 

 

37

 

 

 

 

 

 

 

 

 

 

Natural Gas

 

 

54

 

 

 

 

60

 

 

 

 

 

 

 

 

 

 

 

 

 

 

55

 

 

 

 

63

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Core Assets Production

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil (Mbbls/d)

 

 

82.4

 

 

 

 

73.6

 

 

 

 

 

 

 

 

 

 

 

 

 

 

81.4

 

 

 

 

67.9

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

NGLs – Plant Condensate (Mbbls/d)

 

 

33.6

 

 

 

 

22.4

 

 

 

 

 

 

 

 

 

 

 

 

 

 

31.8

 

 

 

 

21.1

 

 

 

 

 

 

 

 

 

 

NGLs – Other (Mbbls/d)

 

 

35.8

 

 

 

 

22.8

 

 

 

 

 

 

 

 

 

 

 

 

 

 

33.5

 

 

 

 

22.0

 

 

 

 

 

 

 

 

 

 

Total NGLs (Mbbls/d)

 

 

69.4

 

 

 

 

45.2

 

 

 

 

 

 

 

 

 

 

 

 

 

 

65.3

 

 

 

 

43.1

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total Oil & NGLs (Mbbls/d)

 

 

151.8

 

 

 

 

118.8

 

 

 

 

 

 

 

 

 

 

 

 

 

 

146.7

 

 

 

 

111.0

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural Gas (MMcf/d)

 

 

1,027

 

 

 

 

768

 

 

 

 

 

 

 

 

 

 

 

 

 

 

1,013

 

 

 

 

786

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total Production (MBOE/d)

 

 

322.9

 

 

 

 

246.5

 

 

 

 

 

 

 

 

 

 

 

 

 

 

315.3

 

 

 

 

242.0

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

% of Total Encana Production

 

 

96

 

 

 

 

78

 

 

 

 

 

 

 

 

 

 

 

 

 

 

95

 

 

 

 

76

 

 

 

 

 

 

 

 

 

 

 

(1)

Average daily.

(2)

Average per-unit prices, excluding the impact of risk management activities.

 

42


 

Upstream Product Revenues

 

 

 

Three months ended June 30,

 

 

 

 

Six months ended June 30,

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

($ millions)

 

Oil

 

 

NGLs (1)

 

 

Natural Gas (2)

 

 

Total

 

 

 

 

Oil

 

 

NGLs (1)

 

 

Natural Gas (2)

 

 

Total

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2017 Upstream Product Revenues

 

$

325

 

 

$

135

 

 

$

268

 

 

$

728

 

 

 

 

$

625

 

 

$

269

 

 

$

572

 

 

$

1,466

 

Increase (decrease) due to:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Sales prices

 

 

158

 

 

 

72

 

 

 

(55

)

 

 

175

 

 

 

 

 

262

 

 

 

103

 

 

 

(61

)

 

 

304

 

Production volumes

 

 

28

 

 

 

76

 

 

 

(26

)

 

 

78

 

 

 

 

 

98

 

 

 

142

 

 

 

(83

)

 

 

157

 

2018 Upstream Product Revenues

 

$

511

 

 

$

283

 

 

$

187

 

 

$

981

 

 

 

 

$

985

 

 

$

514

 

 

$

428

 

 

$

1,927

 

 

(1)

Includes plant condensate.

(2)

Natural gas revenues for the second quarter and the first six months of 2018 exclude a royalty adjustment with no associated production volumes of $3 million and $14 million, respectively (2017 - $1 million and $1 million, respectively).

Oil Revenues

Three months ended June 30, 2018 versus June 30, 2017

Oil revenues increased $186 million compared to the second quarter of 2017 primarily due to:

 

Higher average realized oil prices of $20.41 per bbl, or 44 percent, increased revenues by $158 million. The increase reflected a higher WTI benchmark price which was up 41 percent and exposure to other downstream benchmark prices in 2018 resulting from the diversification of the Company’s markets; and

 

Higher average oil production volumes of 7.2 Mbbls/d increased revenues by $28 million. Higher volumes were primarily due to successful drilling program in Permian (17.9 Mbbls/d), partially offset by natural declines in Eagle Ford (7.9 Mbbls/d) and asset sales (1.1 Mbbls/d), which mainly include the Piceance natural gas assets in the third quarter of 2017 and the Tuscaloosa Marine Shale assets in the second quarter of 2017.

Six months ended June 30, 2018 versus June 30, 2017

Oil revenues increased $360 million compared to the first six months of 2017 primarily due to:

 

Higher average realized oil prices of $17.21 per bbl, or 36 percent, increased revenues by $262 million. The increase reflected a higher WTI benchmark price which was up 30 percent and exposure to other downstream benchmark prices in 2018 resulting from the diversification of the Company’s markets. The increase was also due to improved regional pricing; and

 

Higher average oil production volumes of 11.4 Mbbls/d increased revenues by $98 million. Higher volumes were primarily due to successful drilling program in Permian (18.6 Mbbls/d), partially offset by natural declines in Eagle Ford (4.2 Mbbls/d) and asset sales (1.7 Mbbls/d), which mainly include the Tuscaloosa Marine Shale assets in the second quarter of 2017 and the Piceance natural gas assets in the third quarter of 2017.

NGL Revenues

Three months ended June 30, 2018 versus June 30, 2017

NGL revenues increased $148 million compared to the second quarter of 2017 primarily due to:

 

Higher average realized NGL prices of $13.08 per bbl, or 42 percent, increased revenues by $72 million. The increase reflected higher WTI and Edmonton Condensate benchmark prices which were up 41 percent and 38 percent, respectively, as well as improved regional pricing; and

 

Higher average NGL production volumes of 23.2 Mbbls/d increased revenues by $76 million. Higher volumes were primarily due to successful drilling programs in Montney and Permian (31.6 Mbbls/d), partially offset by increased downtime resulting from scheduled plant maintenance for processing liquids rich volumes in Montney (3.6 Mbbls/d) and natural declines in Duvernay (2.6 Mbbls/d).

 

43


 

Six months ended June 30, 2018 versus June 30, 2017

NGL revenues increased $245 million compared to the first six months of 2017 primarily due to:

 

Higher average realized NGL prices of $10.25 per bbl, or 31 percent, increased revenues by $103 million. The increase reflected higher WTI and Edmonton Condensate benchmark prices which were up 30 percent and 26 percent, respectively, as well as improved regional pricing; and

 

Higher average NGL production volumes of 20.9 Mbbls/d increased revenues by $142 million. Higher volumes were primarily due to successful drilling programs in Montney and Permian (26.5 Mbbls/d), partially offset by increased downtime resulting from scheduled plant maintenance for processing liquids rich volumes in Montney (1.7 Mbbls/d), natural declines in Duvernay (1.7 Mbbls/d) and asset sales (1.4 Mbbls/d), which mainly include the Piceance natural gas assets in the third quarter of 2017.

Natural Gas Revenues

Three months ended June 30, 2018 versus June 30, 2017

Natural gas revenues decreased $81 million compared to the second quarter of 2017 primarily due to:

 

Lower average realized natural gas prices of $0.70 per Mcf, or 27 percent, decreased revenues by $55 million. The decrease reflected lower NYMEX and AECO benchmark prices which were down 12 percent and 63 percent, respectively, partially offset by exposure to other downstream benchmark prices in 2018 resulting from the diversification of the Company’s markets; and

 

Lower average natural gas production volumes of 51 MMcf/d decreased revenues by $26 million. Lower volumes were primarily due to asset sales (294 MMcf/d), which mainly include the Piceance natural gas assets in the third quarter of 2017 and certain assets in Wheatland in the fourth quarter of 2017, lower activity in Other Upstream Operations (23 MMcf/d) and natural declines in Duvernay (10 MMcf/d), partially offset by successful drilling programs in Montney and Permian (258 MMcf/d), and decreased downtime resulting from scheduled plant maintenance in Montney (28 MMcf/d).

Six months ended June 30, 2018 versus June 30, 2017

Natural gas revenues decreased $144 million compared to the first six months of 2017 primarily due to:

 

Lower average realized natural gas prices of $0.48 per Mcf, or 18 percent, decreased revenues by $61 million. The decrease reflected lower NYMEX and AECO benchmark prices which were down 11 percent and 50 percent, respectively, partially offset by exposure to other downstream benchmark prices in 2018 resulting from the diversification of the Company’s markets; and

 

Lower average natural gas production volumes of 109 MMcf/d decreased revenues by $83 million. Lower volumes were primarily due to asset sales (299 MMcf/d), which mainly include the Piceance natural gas assets in the third quarter of 2017 and certain assets in Wheatland in the fourth quarter of 2017, and lower activity in Other Upstream Operations (46 MMcf/d), partially offset by successful drilling programs in Montney and Permian (228 MMcf/d) and decreased downtime resulting from scheduled plant maintenance in Montney (14 MMcf/d).

Gains (Losses) on Risk Management, Net

As a means of managing commodity price volatility, Encana enters into commodity derivative financial instruments on a portion of its expected oil, NGL and natural gas production volumes. The Company’s commodity price mitigation program reduces volatility and helps sustain revenues during periods of lower prices. Further information on the Company’s commodity price positions as at June 30, 2018 can be found in Note 19 to the Consolidated Financial Statements included in Part I, Item 1 of this Quarterly Report on Form 10-Q.

 

 

 

 

44


 

The following table s provide the effects of Encana’s risk management activities on revenues.

 

 

 

 

Three months ended June 30,

 

 

 

 

Six months ended June 30,

 

($ millions)

 

 

2018

 

 

2017

 

 

 

 

2018

 

 

2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Realized Gains (Losses) on Risk Management

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity Price (1)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil

 

 

$

(65

)

 

$

16

 

 

 

 

$

(121

)

 

$

16

 

NGLs (2)

 

 

 

(37

)

 

 

2

 

 

 

 

 

(58

)

 

 

1

 

Natural Gas

 

 

 

116

 

 

 

-

 

 

 

 

 

160

 

 

 

(25

)

Other (3)

 

 

 

-

 

 

 

1

 

 

 

 

 

1

 

 

 

3

 

Total

 

 

 

14

 

 

 

19

 

 

 

 

 

(18

)

 

 

(5

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Unrealized Gains (Losses) on Risk Management

 

 

 

(326

)

 

 

110

 

 

 

 

 

(258

)

 

 

472

 

Total Gains (Losses) on Risk Management, Net

 

 

$

(312

)

 

$

129

 

 

 

 

$

(276

)

 

$

467

 

 

 

 

 

Three months ended June 30,

 

 

 

 

Six months ended June 30,

 

(Per-unit)

 

 

2018

 

 

2017

 

 

 

 

2018

 

 

2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Realized Gains (Losses) on Risk Management

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity Price

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil ($/bbl)

 

 

$

(8.52

)

 

$

2.16

 

 

 

 

$

(8.04

)

 

$

1.19

 

NGLs ($/bbl) (1)

 

 

$

(5.63

)

 

$

0.73

 

 

 

 

$

(4.76

)

 

$

0.19

 

Natural Gas ($/Mcf)

 

 

$

1.16

 

 

$

(0.01

)

 

 

 

$

0.81

 

 

$

(0.12

)

Total ($/BOE)

 

 

$

0.44

 

 

$

0.62

 

 

 

 

$

(0.32

)

 

$

(0.14

)

 

(1)

Includes realized gains and losses related to the Canadian and USA Operations.

(2)

Includes plant condensate.

(3)

Other primarily includes realized gains or losses from Market Optimization and other derivative contracts with no associated production volumes.

Encana recognizes fair value changes from its risk management activities each reporting period. The changes in fair value result from new positions and settlements that occur during each period, as well as the relationship between contract prices and the associated forward curves. Realized gains or losses on risk management activities related to commodity price mitigation are included in the Canadian Operations, USA Operations and Market Optimization revenues as the contracts are cash settled . Unrealized gains or losses on fair value changes of unsettled contracts are included in the Corporate and Other segment.

Market Optimization Revenues

Market Optimization revenues relate to activities that provide operational flexibility and cost mitigation for transportation commitments, product type, delivery points and customer diversification.

 

 

 

 

Three months ended June 30,

 

 

 

 

Six months ended June 30,

 

($ millions)

 

 

2018

 

 

2017

 

 

 

 

2018

 

 

2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Market Optimization

 

 

$

291

 

 

$

204

 

 

 

 

$

592

 

 

$

390

 

 

Three months ended June 30, 2018 versus June 30, 2017

Market Optimization revenues increased $87 million compared to the second quarter of 2017 primarily due to:

 

Higher sales of third-party purchased volumes, primarily related to natural gas, used for optimization activities and long-term marketing arrangements associated with the Company’s previous divestitures ($175 million), partially offset by lower natural gas commodity prices ($88 million).

 

45


 

Six months ended June 30, 2018 versus June 30, 2017

Market Optimization revenues increased $202 million compared to the first six months of 2017 primarily due to:

 

Higher sales of third-party purchased volumes, primarily related to natural gas, used for optimization activities and long-term marketing arrangements associated with the Company’s previous divestitures ($343 million), partially offset by lower natural gas commodity prices ($141 million).

Sublease Revenues

Sublease revenues primarily include amounts related to the sublease of office space in The Bow office building recorded in the Corporate and Other segment. Further information on The Bow office sublease can be found in Note 11 to the Consolidated Financial Statements included in Part I, Item 1 of this Quarterly Report on Form 10-Q.


Operating Expenses

Production, Mineral and Other Taxes

Production, mineral and other taxes include production and property taxes. Production taxes are generally assessed as a percentage of oil and natural gas production revenues. Property taxes are generally assessed based on the value of the underlying assets.

 

 

 

 

Three months ended June 30,

 

 

 

 

Six months ended June 30,

 

($ millions)

 

 

2018

 

 

2017

 

 

 

 

2018

 

 

2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Canadian Operations

 

 

$

4

 

 

$

5

 

 

 

 

$

8

 

 

$

10

 

USA Operations

 

 

 

31

 

 

 

19

 

 

 

 

 

56

 

 

 

43

 

Total

 

 

$

35

 

 

$

24

 

 

 

 

$

64

 

 

$

53

 

 

 

 

 

Three months ended June 30,

 

 

 

 

Six months ended June 30,

 

($/BOE)

 

 

2018

 

 

2017

 

 

 

 

2018

 

 

2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Canadian Operations

 

 

$

0.21

 

 

$

0.39

 

 

 

 

$

0.22

 

 

$

0.34

 

USA Operations

 

 

$

2.48

 

 

$

1.29

 

 

 

 

$

2.31

 

 

$

1.55

 

Total

 

 

$

1.13

 

 

$

0.85

 

 

 

 

$

1.06

 

 

$

0.93

 

 

Three months ended June 30, 2018 versus June 30, 2017

Production, mineral and other taxes increased $11 million compared to the second quarter of 2017 primarily due to:

 

Higher liquids prices and production volumes in Permian ($8 million) and the recovery of certain production taxes in the USA Operations in 2017 ($7 million) ;

partially offset by :

 

Asset sales ($5 million), which mainly include the Piceance natural gas assets in the third quarter of 2017 and certain assets in Wheatland in the fourth quarter of 2017.

Six months ended June 30, 2018 versus June 30, 2017

Production, mineral and other taxes increased $11 million compared to the first six months of 2017 primarily due to:

 

Higher liquids prices and production volumes in Permian ($15 million) and the recovery of certain production taxes in the USA Operations in 2017 ($3 million).

partially offset by :

 

Asset sales ($10 million), which mainly include the Piceance natural gas assets in the third quarter of 2017 and certain assets in Wheatland in the fourth quarter of 2017.

 

46


 

Transportation and Processing

Transportation and processing expense includes transportation costs incurred to move product from production points to sales points including gathering, compression, pipeline tariffs, trucking and storage costs. Encana also incurs costs related to processing provided by third parties or through ownership interests in processing facilities to bring raw production to sales- quality product.

 

 

 

 

Three months ended June 30,

 

 

 

 

Six months ended June 30,

 

($ millions)

 

 

2018

 

 

2017

 

 

 

 

2018

 

 

2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Canadian Operations

 

 

$

207

 

 

$

133

 

 

 

 

$

397

 

 

$

265

 

USA Operations

 

 

 

31

 

 

 

51

 

 

 

 

 

58

 

 

 

110

 

Upstream Transportation and Processing

 

 

 

238

 

 

 

184

 

 

 

 

 

455

 

 

 

375

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Market Optimization

 

 

 

34

 

 

 

22

 

 

 

 

 

66

 

 

 

43

 

Corporate & Other

 

 

 

-

 

 

 

-

 

 

 

 

 

-

 

 

 

-

 

Total

 

 

$

272

 

 

$

206

 

 

 

 

$

521

 

 

$

418

 

 

 

 

 

Three months ended June 30,

 

 

 

 

Six months ended June 30,

 

($/BOE)

 

 

2018

 

 

2017

 

 

 

 

2018

 

 

2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Canadian Operations

 

 

$

11.29

 

 

$

9.30

 

 

 

 

$

11.09

 

 

$

8.91

 

USA Operations

 

 

$

2.51

 

 

$

3.54

 

 

 

 

$

2.39

 

 

$

3.97

 

Upstream Transportation and Processing

 

 

$

7.73

 

 

$

6.39

 

 

 

 

$

7.58

 

 

$

6.53

 

 

Three months ended June 30, 2018 versus June 30, 2017

Transportation and processing expense increased $66 million compared to the second quarter of 2017 primarily due to:

 

Higher downstream processing and transportation costs due to higher volumes primarily in Montney and Permian and costs relating to the diversification of the Company’s downstream markets ($46 million), higher volumes and gathering and processing fees in Montney and Permian ($42 million) and the higher U.S./Canadian dollar exchange rate ($6 million);

partially offset by:

 

Asset sales ($30 million), which mainly include the Piceance natural gas assets in the third quarter of 2017.

Six months ended June 30, 2018 versus June 30, 2017

Transportation and processing expense increased $103 million compared to the first six months of 2017 primarily due to:

 

Higher downstream processing and transportation costs due to higher volumes primarily in Montney and Permian and costs relating to the diversification of the Company’s downstream markets ($87 million), higher volumes and gathering and processing fees in Montney and Permian ($74 million) and the higher U.S./Canadian dollar exchange rate ($12 million);

partially offset by:

 

Asset sales ($61 million), which mainly include the Piceance natural gas assets in the third quarter of 2017.

 

47


 

Operating

Operating expense includes costs paid by Encana, net of amounts capitalized, to operate oil and gas properties in which the Company has a working interest. These costs primarily include labour, service contract fees, chemicals and fuel.

 

 

 

 

Three months ended June 30,

 

 

 

 

Six months ended June 30,

 

($ millions)

 

 

2018

 

 

2017

 

 

 

 

2018

 

 

2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Canadian Operations

 

 

$

35

 

 

$

22

 

 

 

 

$

64

 

 

$

53

 

USA Operations

 

 

 

84

 

 

 

84

 

 

 

 

 

158

 

 

 

171

 

Upstream Operating Expense

 

 

 

119

 

 

 

106

 

 

 

 

 

222

 

 

 

224

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Market Optimization

 

 

 

13

 

 

 

3

 

 

 

 

 

17

 

 

 

12

 

Corporate & Other

 

 

 

5

 

 

 

4

 

 

 

 

 

9

 

 

 

9

 

Total

 

 

$

137

 

 

$

113

 

 

 

 

$

248

 

 

$

245

 

 

 

 

 

Three months ended June 30,

 

 

 

 

Six months ended June 30,

 

($/BOE)

 

 

2018

 

 

2017

 

 

 

 

2018

 

 

2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Canadian Operations

 

 

$

1.89

 

 

$

1.52

 

 

 

 

$

1.75

 

 

$

1.73

 

USA Operations

 

 

$

6.75

 

 

$

5.60

 

 

 

 

$

6.52

 

 

$

5.99

 

Upstream Operating Expense (1)

 

 

$

3.86

 

 

$

3.58

 

 

 

 

$

3.67

 

 

$

3.78

 

 

(1)

Upstream Operating Expense per BOE for the second quarter and first six months of 2018 includes long-term incentive costs of $0.46/BOE and $0.17/BOE, respectively (2017 - recovery of long-term incentive costs of $0.18/BOE and $0.01/BOE, respectively).

Three months ended June 30, 2018 versus June 30, 2017

Operating expense increased $24 million compared to the second quarter of 2017 primarily due to:

 

Long-term incentive costs resulting from the increase in Encana’s share price in the second quarter of 2018 ($30 million) and higher activity in Permian and Montney ($11 million).

partially offset by:

 

Asset sales ($15 million), which mainly include the Piceance natural gas assets in the third quarter of 2017 and certain assets in Wheatland in the fourth quarter of 2017.

Six months ended June 30, 2018 versus June 30, 2017

Operating expense increased $3 million compared to the first six months of 2017 primarily due to:

 

Higher activity in Permian and Montney ($23 million) and long-term incentive costs resulting from the increase in Encana’s share price in the first six months of 2018 ($16 million).

partially offset by:

 

Asset sales ($33 million), which mainly include the Piceance natural gas assets in the third quarter of 2017 and certain assets in Wheatland in the fourth quarter of 2017.

Further information on Encana’s long-term incentives can be found in Note 16 to the Consolidated Financial Statements included in Part I, Item 1 of this Quarterly Report on Form 10-Q.


 

48


 

Purchased Product

Purchased product expense includes purchases of oil, NGLs and natural gas from third parties that are used to provide operational flexibility and cost mitigation for transportation commitments, product type, delivery points and customer diversification.

 

 

 

 

Three months ended June 30,

 

 

 

 

Six months ended June 30,

 

($ millions)

 

 

2018

 

 

2017

 

 

 

 

2018

 

 

2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Market Optimization

 

 

$

248

 

 

$

192

 

 

 

 

$

521

 

 

$

363

 

 

Three months ended June 30, 2018 versus June 30, 2017

Purchased product expense increased $56 million compared to the second quarter of 2017 primarily due to:

 

Higher third-party volumes purchased, primarily related to natural gas, for optimization activities and long-term marketing arrangements associated with the Company’s previous divestitures ($159 million), partially offset by lower natural gas commodity prices ($103 million).

Six months ended June 30, 2018 versus June 30, 2017

Purchased product expense increased $158 million compared to the first six months of 2017 primarily due to:

 

Higher third-party volumes purchased, primarily related to natural gas, for optimization activities and long-term marketing arrangements associated with the Company’s previous divestitures ($321 million), partially offset by lower natural gas commodity prices ($163 million).

Depreciation, Depletion & Amortization

Proved properties within each country cost centre are depleted using the unit-of-production method based on proved reserves as discussed in Note 1 to the Consolidated Financial Statements included in Item 8 of the 2017 Annual Report on Form 10-K . Depletion rates are impacted by impairments, acquisitions, divestitures and foreign exchange rates as well as fluctuations in 12-month average trailing prices which affect proved reserves volumes. Additional information can be found in the Critical Accounting Estimates section of the MD&A included in Item 7 of the 2017 Annual Report on Form 10-K. Corporate assets are carried at cost and depreciated on a straight-line basis over the estimated service lives of the assets.

 

 

 

 

Three months ended June 30,

 

 

 

 

Six months ended June 30,

 

($ millions)

 

 

2018

 

 

2017

 

 

 

 

2018

 

 

2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Canadian Operations

 

 

$

85

 

 

$

53

 

 

 

 

$

162

 

 

$

117

 

USA Operations

 

 

 

202

 

 

 

123

 

 

 

 

 

387

 

 

 

229

 

Upstream DD&A

 

 

 

287

 

 

 

176

 

 

 

 

 

549

 

 

 

346

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Market Optimization

 

 

 

1

 

 

 

-

 

 

 

 

 

1

 

 

 

-

 

Corporate & Other

 

 

 

12

 

 

 

17

 

 

 

 

 

25

 

 

 

34

 

Total

 

 

$

300

 

 

$

193

 

 

 

 

$

575

 

 

$

380

 

 

 

 

 

Three months ended June 30,

 

 

 

 

Six months ended June 30,

 

($/BOE)

 

 

2018

 

 

2017

 

 

 

 

2018

 

 

2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Canadian Operations

 

 

$

4.67

 

 

$

3.72

 

 

 

 

$

4.53

 

 

$

3.92

 

USA Operations

 

 

$

16.15

 

 

$

8.47

 

 

 

 

$

16.00

 

 

$

8.29

 

Upstream DD&A

 

 

$

9.33

 

 

$

6.12

 

 

 

 

$

9.16

 

 

$

6.02

 

 


 

49


 

Three months ended June 30, 2018 versus June 30, 2017

DD&A increased $107 million compared to the second quarter of 2017 primarily due to:

 

Higher depletion rates primarily in the USA Operations ($109 million) and higher volumes in the Canadian Operations ($13 million);

partially offset by:

 

Lower volumes in the USA Operations ($14 million);

The depletion rates in the Canadian and USA Operations increased $0.95 per BOE and $7.68 per BOE, respectively, compared to the second quarter of 2017 primarily due to:

 

Higher capital spending and changes in Encana’s development plans as a result of the increased capital program for 2018 and lower reserve volumes from the sale of the Piceance natural gas assets in the third quarter of 2017.

Six months ended June 30, 2018 versus June 30, 2017

DD&A increased $195 million compared to the first six months of 2017 primarily due to:

 

Higher depletion rates primarily in the USA Operations ($199 million) and higher volumes in the Canadian Operations ($20 million);

partially offset by:

 

Lower volumes in the USA Operations ($22 million);

The depletion rates in the Canadian and USA Operations increased $0.61 per BOE and $7.71 per BOE, respectively, compared to the first six months of 2017 primarily due to:

 

Higher capital spending and changes in Encana’s development plans as a result of the increased capital program for 2018 and lower reserve volumes from the sale of the Piceance natural gas assets in the third quarter of 2017.

Administrative

Administrative expense represents costs associated with corporate functions provided by Encana staff in the Calgary and Denver offices. Costs primarily include salaries and benefits, general office, information technology and long-term incentive costs.

 

 

 

 

Three months ended June 30,

 

 

 

 

Six months ended June 30,

 

 

 

 

2018

 

 

2017

 

 

 

 

2018

 

 

2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Administrative ($ millions)

 

 

$

99

 

 

$

24

 

 

 

 

$

130

 

 

$

82

 

Administrative ($/BOE) (1)

 

 

$

3.20

 

 

$

0.82

 

 

 

 

$

2.17

 

 

$

1.43

 

 

(1)

Administrative expense per BOE for the second quarter and first six months of 2018 includes long-term incentive costs of $1.84/BOE and $0.74/BOE, respectively (2017 - recovery of long-term incentive costs of $0.79/BOE and $0.13/BOE, respectively).

 

Three months ended June 30, 2018 versus June 30, 2017

Administrative expense in the second quarter of 2018 increased $75 million compared to the second quarter of 2017 primarily due to long-term incentive costs resulting from the increase in Encana’s share price in the second quarter of 2018 ($78 million).

Six months ended June 30, 2018 versus June 30, 2017

Administrative expense in the first six months of 2018 increased $48 million compared to the first six months of 2017 primarily due to long-term incentive costs resulting from the increase in Encana’s share price in the first six months of 2018 ($51 million).


 

50


 

Other (I ncome) Expenses

 

 

 

 

Three months ended June 30,

 

 

 

 

Six months ended June 30,

 

($ millions)

 

 

2018

 

 

2017

 

 

 

 

2018

 

 

2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest

 

 

$

81

 

 

$

79

 

 

 

 

$

173

 

 

$

167

 

Foreign exchange (gain) loss, net

 

 

 

25

 

 

 

(58

)

 

 

 

 

116

 

 

 

(84

)

(Gain) loss on divestitures, net

 

 

 

(1

)

 

 

-

 

 

 

 

 

(4

)

 

 

1

 

Other (gains) losses, net

 

 

 

-

 

 

 

(27

)

 

 

 

 

(3

)

 

 

(35

)

Total Other (Income) Expenses

 

 

$

105

 

 

$

(6

)

 

 

 

$

282

 

 

$

49

 

 

Interest

 

Interest expense primarily includes interest on Encana’s long-term debt arising from U.S. dollar denominated unsecured notes and balances drawn on the Company’s credit facilities. Encana also incurs interest on the Company’s long-term obligation for The Bow office building and capital leases. Further details on changes in interest can be found in Note 5 to the Consolidated Financial Statements included in Part I, Item 1 of this Quarterly Report on Form 10-Q.

 

Foreign Exchange (Gain) Loss, Net

Foreign exchange gains and losses result from the impact of fluctuations in the Canadian to U.S. dollar exchange rate. Further details on changes in foreign exchange gains or losses can be found in Note 6 to the Consolidated Financial Statements included in Part I, Item 1 of this Quarterly Report on Form 10-Q. Additional information on foreign exchange rates and the effects of foreign exchange rate changes can be found in Item 3 of this Quarterly Report on Form 10-Q.

In the second quarter of 2018, Encana recorded a net foreign exchange loss of $25 million compared to a net gain of $58 million in 2017. The change was primarily due to unrealized foreign exchange losses on the translation of U.S. dollar financing debt issued from Canada compared to gains in 2017 ($135 million) and on the translation of U.S. dollar risk management contracts issued from Canada compared to gains in 2017 ($29 million), partially offset by unrealized foreign exchange gains on the translation of intercompany notes compared to losses in 2017 ($72 million).

In the first six months of 2018, Encana recorded a net foreign exchange loss of $116 million compared to a net gain of $84 million in 2017. The change was primarily due to unrealized foreign exchange losses on the translation of U.S. dollar financing debt issued from Canada compared to gains in 2017 ($290 million) and on the translation of U.S. dollar risk management contracts issued from Canada compared to gains in 2017 ($42 million), partially offset by unrealized foreign exchange gains on the translation of intercompany notes compared to losses in 2017 ($54 million) and realized foreign exchange gains on the settlement of intercompany notes compared to losses in 2017 ($49 million).

Other (Gains) Losses, Net

Other (gains) losses, net primarily includes other non-recurring revenues or expenses and may also include items such as interest income on short-term investments, interest received from tax authorities, reclamation charges relating to decommissioned assets and earnings/losses from equity investments.

Other gains in the second quarter and first six months of 2017 primarily includes interest received of $26 million and $33 million, respectively, resulting from the successful resolution of certain tax items previously assessed by the tax authorities relating to prior taxation years.

 

 

 


 

51


 

Income Tax

 

 

 

 

Three months ended June 30,

 

 

 

 

Six months ended June 30,

 

($ millions)

 

 

2018

 

 

2017

 

 

 

 

2018

 

 

2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current Income Tax Expense (Recovery)

 

 

$

(64)

 

 

$

(18

)

 

 

 

$

(61)

 

 

$

(57

)

Deferred Income Tax Expense (Recovery)

 

 

 

(6)

 

 

 

14

 

 

 

 

 

-

 

 

 

56  

 

Income Tax Expense (Recovery)

 

 

$

(70)

 

 

$

(4

)

 

 

 

$

(61)

 

 

$

(1

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Effective Tax Rate

 

 

31.7%

 

 

(1.2%

)

 

 

 

100.0%

 

 

(0.1%

)

 

Income Tax Expense (Recovery)

Three months ended June 30, 2018 versus June 30, 2017

In the second quarter of 2018, Encana recorded a higher current income tax recovery compared to 2017. The higher income tax recovery was primarily due to the resolution of certain tax items relating to prior taxation years.

Deferred income tax in the second quarter was a recovery compared to an expense in 2017 primarily due to:

 

Net loss before income tax in 2018 compared to net earnings before income tax in 2017; and

 

A reduction in the U.S. federal corporate tax rate to 21 percent from 35 percent resulting from U.S. Tax Reform.

Six months ended June 30, 2018 versus June 30, 2017

In the first six months of 2018, Encana recorded a lower deferred income tax expense compared to 2017 primarily due to a net loss before income tax in 2018 compared to net earnings before income tax in 2017 and U.S. Tax Reform, both as discussed above.

There has been no change in 2018 to the provisional tax adjustment recognized in December 2017 resulting from the re‑measurement of the Company’s tax position due to a reduction of the U.S federal corporate tax rate under U.S. Tax Reform. Additional information on U.S. Tax Reform can be found in Note 6 to the Consolidated Financial Statements included in Item 8 of the 2017 Annual Report on Form 10-K.  

Effective Tax Rate

Encana’s interim income tax expense is determined using the estimated annual effective income tax rate applied to year-to-date net earnings before income tax plus the effect of legislative changes and amounts in respect of prior periods. The estimated annual effective income tax rate is impacted by expected annual earnings, income tax related to foreign operations, the effect of legislative changes including U.S. Tax Reform, non-taxable capital gains and losses, tax differences on divestitures and transactions, and partnership tax allocations in excess of funding. The Company’s effective tax rate was 31.7 percent for the second quarter and 100 percent for the first six months of 2018, which are higher than the Canadian statutory rate of 27 percent primarily due to the impact of the foreign jurisdictional tax rates relative to the Canadian statutory tax rate applied to jurisdictional earnings as well as the current year items discussed above.

Tax interpretations, regulations and legislation, including U.S. Tax Reform and potential Treasury Department regulations and guidance, in the various jurisdictions in which the Company and its subsidiaries operate are subject to change and interpretation. As a result, there are tax matters under review for which the timing of resolution is uncertain. The Company believes that the provision for income taxes is adequate.  

 

 

52


 

Liquidity and Ca pital Resources

Sources of Liquidity

The Company has the flexibility to access cash equivalents and a range of funding alternatives at competitive rates through committed revolving bank credit facilities as well as debt and equity capital markets. Encana closely monitors the accessibility of cost-effective credit and ensures that sufficient liquidity is in place to fund capital expenditures and dividend payments. In addition, the Company may use cash and cash equivalents, cash from operating activities, or proceeds from asset divestitures and share issuances to fund its operations or to manage its capital structure as discussed below. At June 30, 2018, $154 million in cash and cash equivalents was held by U.S. subsidiaries. The cash held by U.S. subsidiaries is accessible and may be subject to additional Canadian income taxes and U.S. withholding taxes if repatriated.

The 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 practice of maintaining capital discipline and strategically managing its capital structure by adjusting capital spending, adjusting dividends paid to shareholders, issuing new shares, purchasing shares for cancellation through a NCIB, issuing new debt or repaying existing debt.

 

 

 

 

As at June 30,

 

($ millions, except as indicated)

 

 

2018

 

 

2017

 

 

 

 

 

 

 

 

 

 

 

Cash and Cash Equivalents

 

 

$

336

 

 

$

395

 

Available Credit Facility – Encana (1)

 

 

 

2,500

 

 

 

3,000

 

Available Credit Facility – U.S. Subsidiary (1)

 

 

 

1,500

 

 

 

1,500

 

Total Liquidity

 

 

$

4,336

 

 

$

4,895

 

 

 

 

 

 

 

 

 

 

 

Long-Term Debt, including current portion

 

 

$

4,198

 

 

$

4,198

 

Total Shareholders’ Equity

 

 

$

6,497

 

 

$

6,783

 

 

 

 

 

 

 

 

 

 

 

Debt to Capitalization (%) (2)

 

 

 

39

 

 

 

38

 

Debt to Adjusted Capitalization (%) (3)

 

 

 

23

 

 

 

22

 

 

(1)

Collectively, the “Credit Facilities”.

(2)

Calculated as long-term debt, including the current portion, divided by shareholders’ equity plus long-term debt, including the current portion.

(3)

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

In the first quarter of 2018, the Company amended the capacity of its Encana Credit Facility from $3.0 billion to $2.5 billion and extended the maturity for both Credit Facilities to July 2022.

Encana is currently in compliance with, and expects that it will continue to be in compliance with, all financial covenants under the Credit Facilities. Management monitors Debt to Adjusted Capitalization, which is a non-GAAP measure defined in the Non-GAAP Measures section of this MD&A, as a proxy for Encana’s financial covenant under the Credit Facilities, which requires debt to adjusted capitalization to be less than 60 percent. The definitions used in the covenant under the Credit Facilities adjust capitalization for cumulative historical ceiling test impairments that were recorded as at December 31, 2011 in conjunction with the Company’s January 1, 2012 adoption of U.S. GAAP. Additional information on financial covenants can be found in Note 12 to the Consolidated Financial Statements included in Item 8 of the 2017 Annual Report on Form 10-K.

 

53


 

Sources and Uses of Cash

In the second quarter and first six months of 2018, Encana primarily generated cash through operating activities. The following table summarizes the sources and uses of the Company’s cash and cash equivalents.

 

 

 

 

 

 

Three months ended June 30,

 

 

 

 

Six months ended June 30,

 

($ millions)

 

Activity Type

 

 

2018

 

 

2017

 

 

 

 

2018

 

 

2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Sources of Cash and Cash Equivalents

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash from operating activities

 

Operating

 

 

$

475

 

 

$

218

 

 

 

 

$

856

 

 

$

324

 

Proceeds from divestitures

 

Investing

 

 

 

46

 

 

 

82

 

 

 

 

 

65

 

 

 

85

 

Other

 

Investing

 

 

 

105

 

 

 

24

 

 

 

 

 

80

 

 

 

79

 

 

 

 

 

 

 

626

 

 

 

324

 

 

 

 

 

1,001

 

 

 

488

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Uses of Cash and Cash Equivalents

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Capital expenditures

 

Investing

 

 

 

595

 

 

 

415

 

 

 

 

 

1,103

 

 

 

814

 

Acquisitions

 

Investing

 

 

 

-

 

 

 

2

 

 

 

 

 

2

 

 

 

48

 

Purchase of common shares

 

Financing

 

 

 

89

 

 

 

-

 

 

 

 

 

200

 

 

 

-

 

Dividends on common shares

 

Financing

 

 

 

14

 

 

 

14

 

 

 

 

 

29

 

 

 

29

 

Other

 

Financing

 

 

 

23

 

 

 

24

 

 

 

 

 

45

 

 

 

40

 

 

 

 

 

 

 

721

 

 

 

455

 

 

 

 

 

1,379

 

 

 

931

 

Foreign Exchange Gain (Loss) on Cash and

   Cash Equivalents Held in Foreign Currency

 

 

 

 

 

(2

)

 

 

3

 

 

 

 

 

(5

)

 

 

4

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Increase (Decrease) in Cash and Cash Equivalents

 

 

 

 

$

(97

)

 

$

(128

)

 

 

 

$

(383

)

 

$

(439

)

 

Operating Activities

Cash from operating activities in the second quarter and first six months of 2018 was $475 million and $856 million, respectively, and was primarily a reflection of recovering commodity prices, changes in production volumes, the Company’s efforts in maintaining cost efficiencies achieved in previous years and changes in non-cash working capital. Additional detail on changes in non-cash working capital can be found in Note 20 to the Consolidated Financial Statements included in Part I, Item 1 of this Quarterly Report on Form 10-Q. Encana expects it will continue to meet the payment terms of its suppliers.

Non-GAAP Cash Flow in the second quarter and first six months of 2018 was $586 million and $986 million, respectively. Non-GAAP Cash Flow was primarily impacted by the items affecting cash from operating activities which are discussed below and in the Results of Operations section of this MD&A.

Three months ended June 30, 2018 versus June 30, 2017

Net cash from operating activities increased $257 million compared to the second quarter of 2017 primarily due to:

 

Higher realized commodity prices ($175 million), higher production volumes ($78 million), higher current tax recovery ($46 million) and changes in non-cash working capital ($23 million);

partially offset by:

 

Higher transportation and processing expense ($66 million) and lower interest income recorded in other gains ($25 million).

Six months ended June 30, 2018 versus June 30, 2017

Net cash from operating activities increased $532 million compared to the first six months of 2017 primarily due to:

 

Higher realized commodity prices ($304 million), changes in non-cash working capital ($175 million) and higher production volumes ($157 million);

partially offset by:

 

Higher transportation and processing expense ($103 million) and lower interest income recorded in other gains ($31 million).

 

54


 

Investing Activities

Cash used in investing activities in the first six months of 2018 was $960 million primarily due to capital expenditures. Capital expenditures in the first six months of 2018 increased $289 million compared to 2017 due to an increase in the Company’s capital program for 2018. This increase was primarily in Montney ($202 million) and Permian ($63 million). Capital expenditures exceeded cash from operating activities by $247 million and the difference was funded using cash on hand and proceeds from divestitures.

Divestitures in the first six months of 2018 were $65 million, which primarily included the sale of the Pipestone midstream assets in Alberta. Divestitures in the first six months of 2017 were $85 million, which primarily included the sale of the Tuscaloosa Marine Shale assets in Mississippi and Louisiana, as well as the sale of certain properties that did not complement Encana’s existing portfolio of assets.

Acquisitions in the first six months of 2018 and 2017 were $2 million and $48 million, respectively, which primarily included land purchases with oil and liquids rich potential.

Capital expenditures and acquisition and divestiture activity are summarized in Notes 3 and 8 to the Consolidated Financial Statements included in Part I, Item 1 of this Quarterly Report on Form 10-Q.

Financing Activities

Net cash used in financing activities in the first six months of 2018 increased $205 million compared to the first six months of 2017. The change was primarily due to the purchase of common shares under a NCIB in the first six months of 2018 ($200 million) as discussed below.

Encana’s long-term debt, excluding the current portion, totaled $3,698 million at June 30, 2018 and $4,197 million at December 31, 2017. The current portion of long-term debt outstanding was $500 million at June 30, 2018. There was no current portion of long-term debt outstanding at December 31, 2017. Encana has no long-term debt maturities until May 2019 and, as at June 30, 2018, over 73 percent of the Company’s debt is not due until 2030 and beyond.  

The Company continues to have full access to the Credit Facilities, which remain committed through July 2022. The Credit Facilities provide financial flexibility and allow the Company to fund its operations, development activities or capital program. At June 30, 2018, Encana had no outstanding balance under the Credit Facilities and $147 million in undrawn letters of credit issued in the normal course of business primarily as collateral security, to support future abandonment liabilities and for transportation arrangements.

Dividends

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

 

 

 

 

Three months ended June 30,

 

 

 

 

Six months ended June 30,

 

($ millions, except as indicated)

 

 

2018

 

 

2017

 

 

 

 

2018

 

 

2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Dividend Payments

 

 

$

14

 

 

$

14

 

 

 

 

$

29

 

 

$

29

 

Dividend Payments ($/share)

 

 

$

0.015

 

 

$

0.015

 

 

 

 

$

0.03

 

 

$

0.03

 

 

On July 31, 2018, the Board of Directors declared a dividend of $0.015 per common share payable on September 28, 2018 to common shareholders of record as of September 14, 2018.

Normal Course Issuer Bid

On February 26, 2018, Encana received approval from the TSX to commence a NCIB that enables the Company to purchase, for cancellation, up to 35 million common shares over a 12-month period from February 28, 2018 to February 27, 2019. The number of shares authorized for purchase represents approximately 3.6 percent of Encana’s issued and outstanding common shares as at February 20, 2018. The Company has authorization from its Board to spend up to $400 million on the NCIB. For the second quarter and first six months of 2018, the Company used cash on hand to purchase approximately 6.8 million and 16.8 million common shares, respectively, for total consideration of approximately $89 million and $200 million, respectively.

 

55


 

For additional information on NCIB, refer to Note 13 to the Consolidated Financial Statements included in Part I, Item 1 of this Quarterly Report on Form 10-Q.

Off-Balance Sheet Arrangements

For information on off-balance sheet arrangements and transactions, refer to the Off-Balance Sheet Arrangements section of the MD&A included in Item 7 of the 2017 Annual Report on Form 10-K.

Commitments and Contingencies

For information on commitments and contingencies, refer to Note 21 to the Consolidated Financial Statements included in Part I, Item 1 of this Quarterly Report on Form 10-Q.

 

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 and should not be viewed as a substitute for measures reported under U.S. GAAP. These measures are commonly used in the oil and gas industry and by Encana to provide shareholders and potential investors with additional information regarding the Company’s liquidity and its ability to generate funds to finance its operations. Non-GAAP measures include: Non-GAAP Cash Flow, Non-GAAP Cash Flow Margin, Debt to Adjusted Capitalization and Net Debt to Adjusted EBITDA. Management’s use of these measures is discussed further below.

Non-GAAP Cash Flow and Non-GAAP Cash Flow Margin

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

Non-GAAP Cash Flow Margin is a non-GAAP measure defined as Non-GAAP Cash Flow per BOE of production.

Management believes these measures are useful to the Company and its investors as a measure of operating and financial performance across periods and against other companies in the industry, and are an indication of the Company’s ability to generate cash to finance capital programs, to service debt and to meet other financial obligations. These measures are used, along with other measures, in the calculation of certain performance targets for the Company’s management and employees.

 

 

 

 

Three months ended June 30,

 

 

 

 

Six months ended June 30,

 

($ millions, except as indicated)

 

 

2018

 

 

2017

 

 

 

 

2018

 

 

2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash From (Used in) Operating Activities

 

 

$

475

 

 

$

218

 

 

 

 

$

856

 

 

$

324

 

(Add back) deduct:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net change in other assets and liabilities

 

 

 

(5

)

 

 

(4

)

 

 

 

 

(16

)

 

 

(16

)

Net change in non-cash working capital

 

 

 

(106

)

 

 

(129

)

 

 

 

 

(114

)

 

 

(289

)

Current tax on sale of assets

 

 

 

-

 

 

 

-

 

 

 

 

 

-

 

 

 

-

 

Non-GAAP Cash Flow

 

 

$

586

 

 

$

351

 

 

 

 

$

986

 

 

$

629

 

Production Volumes (MMBOE)

 

 

 

30.7

 

 

 

28.8

 

 

 

 

 

59.9

 

 

 

57.4

 

Non-GAAP Cash Flow Margin ($/BOE) (1)

 

 

$

19.09

 

 

$

12.19

 

 

 

 

$

16.46

 

 

$

10.96

 

 

(1)

Non-GAAP Cash Flow Margin was previously presented as Corporate Margin.


 

56


 

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 the Credit Facilities which require debt to adjusted capitalization to be less than 60 percent. Adjusted Capitalization includes debt, total shareholders’ equity and an equity adjustment for cumulative historical ceiling test impairments recorded as at December 31, 2011 in conjunction with the Company’s January 1, 2012 adoption of U.S. GAAP.

 

($ millions, except as indicated)

 

 

June 30, 2018

 

 

December 31, 2017

 

 

 

 

 

 

 

 

 

 

 

Long-Term Debt, including current portion

 

 

$

4,198

 

 

$

4,197

 

Total Shareholders’ Equity

 

 

 

6,497

 

 

 

6,728

 

Equity Adjustment for Impairments at December 31, 2011

 

 

 

7,746

 

 

 

7,746

 

Adjusted Capitalization

 

 

$

18,441

 

 

$

18,671

 

Debt to Adjusted Capitalization

 

 

23%

 

 

22%

 


Net Debt to Adjusted EBITDA

Net Debt to Adjusted EBITDA is a non-GAAP measure whereby Net Debt is defined as long-term debt, including the current portion, less cash and cash equivalents and Adjusted EBITDA is defined as trailing 12-month net earnings (loss) before income taxes, DD&A, impairments, accretion of asset retirement obligation, interest, unrealized gains/losses on risk management, foreign exchange gains/losses, gains/losses on divestitures and other gains/losses.

Management believes this measure is useful to the Company and its investors as a measure of financial leverage, the Company’s ability to service its debt and other financial obligations, and as a measure considered comparable to other companies in the industry. This measure is used, along with other measures, in the calculation of certain financial performance targets for the Company’s management and employees.

 

($ millions, except as indicated)

 

 

June 30, 2018

 

 

December 31, 2017

 

 

 

 

 

 

 

 

 

 

 

Long-Term Debt, including current portion

 

 

$

4,198

 

 

$

4,197

 

Less:

 

 

 

 

 

 

 

 

 

Cash and cash equivalents

 

 

 

336

 

 

 

719

 

Net Debt

 

 

 

3,862

 

 

 

3,478

 

 

 

 

 

 

 

 

 

 

 

Net Earnings (Loss)

 

 

 

65

 

 

 

827

 

Add back (deduct):

 

 

 

 

 

 

 

 

 

Depreciation, depletion and amortization

 

 

 

1,028

 

 

 

833

 

Impairments

 

 

 

-

 

 

 

-

 

Accretion of asset retirement obligation

 

 

 

32

 

 

 

37

 

Interest

 

 

 

369

 

 

 

363

 

Unrealized (gains) losses on risk management

 

 

 

288

 

 

 

(442

)

Foreign exchange (gain) loss, net

 

 

 

(79

)

 

 

(279

)

(Gain) loss on divestitures, net

 

 

 

(409

)

 

 

(404

)

Other (gains) losses, net

 

 

 

(10

)

 

 

(42

)

Income tax expense (recovery)

 

 

 

543

 

 

 

603

 

Adjusted EBITDA

 

 

$

1,827

 

 

$

1,496

 

Net Debt to Adjusted EBITDA (times)

 

 

 

2.1

 

 

 

2.3

 

 

 

 

 

57


 

Item 3: Quantitative and Qualitati ve Disclosures About Market Risk

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about Encana’s potential exposure to market risks. The term “market risk” refers to the Company’s risk of loss arising from adverse changes in oil, NGL and natural gas prices, foreign currency exchange rates and interest rates. The following disclosures are not meant to be precise indicators of expected future losses but rather indicators of reasonably possible losses. The forward-looking information provides indicators of how the Company views and manages ongoing market risk exposures. The Company’s policy is to not use derivative financial instruments for speculative purposes.  

COMMODITY PRICE RISK

Commodity price risk arises from the effect fluctuations in future commodity prices, including oil, NGLs and natural gas, may have on future revenues, expenses and cash flows. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to the Company’s natural gas production. Pricing for oil and natural gas production has been volatile and unpredictable as discussed in Item 1A. “Risk Factors” of the 2017 Annual Report on Form 10-K. To partially mitigate exposure to commodity price risk, the Company may enter into various derivative financial instruments including futures, forwards, swaps, options and costless collars. The use of these derivative instruments is governed under formal policies and is subject to limits established by the Board of Directors and may vary from time to time. Both exchange traded and over-the-counter traded derivative instruments may be subject to margin-deposit requirements, and the Company may be required from time to time to deposit cash or provide letters of credit with exchange brokers or counterparties to satisfy these margin requirements. For additional information relating to the Company’s derivative and financial instruments, see Note 19 under Part I, Item 1 of this Quarterly Report on Form 10-Q.

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 as follows:

 

 

 

June 30, 2018

 

(US$ millions)

 

10% Price

Increase

 

 

10% Price

Decrease

 

Crude oil price

 

$

(335

)

 

$

318

 

NGL price

 

 

(12

)

 

 

12

 

Natural gas price

 

 

(59

)

 

 

52

 

 

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 in Canada and the United States, fluctuations in the exchange rate between the U.S. and Canadian dollars can have a significant effect on the Company’s reported results. Although Encana’s financial results are consolidated in Canadian dollars, the Company reports its results in U.S. dollars as most of its revenues are closely tied to the U.S. dollar and to facilitate a more direct comparison to other North American oil and gas companies.

The table below summarizes selected foreign exchange impacts on Encana’s financial results when compared to the same periods in 2017.

 

 

 

Three Months Ended

June 30,

 

 

Six Months Ended

June 30,

 

 

 

$ millions

 

 

$/BOE

 

 

$ millions

 

 

$/BOE

 

Increase (Decrease) in:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Capital Investment

 

$

4

 

 

 

 

 

 

$

8

 

 

 

 

 

Transportation and Processing Expense (1)

 

 

6

 

 

$

0.18

 

 

 

12

 

 

$

0.19

 

Operating Expense (1)

 

 

1

 

 

 

0.04

 

 

 

2

 

 

 

0.04

 

Administrative Expense

 

 

1

 

 

 

0.03

 

 

 

3

 

 

 

0.05

 

Depreciation, Depletion and Amortization (1)

 

 

2

 

 

 

0.07

 

 

 

5

 

 

 

0.09

 

 

(1)

Reflects upstream operations.

 

58


 

Foreign exchange gains and losses also arise when monetary assets and monetary liabilities denominated in foreign currencies are translated and settled, and primarily include:

 

U.S. dollar denominated financing debt issued from Canada

 

U.S. dollar denominated risk management assets and liabilities held in Canada

 

U.S. dollar denominated cash and short-term investments held in Canada

 

Foreign denominated intercompany loans

To partially mitigate the effect of foreign exchange fluctuations on future commodity revenues and expenses, the Company may enter into foreign currency derivative contracts. As at June 30, 2018, Encana has entered into $358 million notional U.S. dollar denominated currency swaps at an average exchange rate of US$0.7606 to C$1, which mature monthly through the remainder of 2018 and $250 million notional U.S. dollar denominated currency swaps at an average exchange rate of US$0.7581 to C$1, which mature monthly throughout 2019.

As at June 30, 2018, Encana had $4.2 billion in U.S. dollar long-term debt and $278 million in U.S. dollar capital leases issued from Canada that were subject to foreign exchange exposure.

The table below summarizes the sensitivity to foreign exchange rate fluctuations, with all other variables held constant. The Company has used a 10 percent variability to assess the potential impact from Canadian to U.S. foreign currency exchange rate changes. Fluctuations in foreign currency exchange rates could have resulted in unrealized gains (losses) impacting pre-tax net earnings as follows:

 

 

 

June 30, 2018

 

(US$ millions)

 

10% Rate

Increase

 

 

10% Rate

Decrease

 

Foreign currency exchange

 

$

(102

)

 

$

124

 

 

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.

As at June 30, 2018, the Company had no floating rate debt and there were no interest rate derivatives outstanding.

 

Item 4: Controls and Procedures

 

DISCLOSURE CONTROLS AND PROCEDURES

 

Encana’s Chief Executive Officer and Chief Financial Officer performed an evaluation of the Company’s disclosure controls and procedures as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (“Exchange Act”). The Company’s disclosure controls and procedures are designed to ensure that information required to be disclosed by the Company in reports it files or submits under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the rules and forms of the SEC, and to ensure that the information required to be disclosed by the Company in reports that it files or submits under the Exchange Act, is accumulated and communicated to the Company’s management, including the principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure. Based on this evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that the Company’s disclosure controls and procedures were effective as of June 30, 2018.

 

CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

 

There were no changes in Encana’s internal control over financial reporting during the second quarter of 2018 that materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

 

59


 

PART II

Item 1. Legal Proceedings

 

Please refer to Item 3 of the 2017 Annual Report on Form 10-K and Note 21 of Encana’s Condensed Consolidated Financial Statements under Part I, Item 1 of this Quarterly Report on Form 10-Q.

 

Item 1A. Risk Factors

 

There have been no material changes from the risk factors disclosed in Item 1A. Risk Factors in the 2017 Annual Report on Form 10-K.

 

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

 

Issuer Purchase of Equity Securities

 

On February 26, 2018, Encana announced it had received approval from the TSX to purchase, for cancellation, up to 35 million common shares pursuant to a NCIB over a 12-month period from February 28, 2018 to February 27, 2019.

 

During the three months ended June 30, 2018, the Company purchased 6.8 million common shares for total consideration of approximately $89 million at a weighted average price of $13.09. The following table presents the common shares purchased during the three months ended June 30, 2018.

 

Period

 

Total Number of

Shares Purchased

 

 

Average

Price Paid

per Share (1)

 

 

Total Number of Shares

Purchased as Part of Publicly

Announced Plans or Programs

 

 

Maximum Number of Shares

That May Yet be Purchased

Under the Plans or Programs

 

April 1 to April 30, 2018

 

 

-

 

 

$

-

 

 

 

-

 

 

 

25,000,000

 

May 1 to May 31, 2018

 

 

5,975,000

 

 

 

13.17

 

 

 

5,975,000

 

 

 

19,025,000

 

June 1 to June 30, 2018

 

 

835,000

 

 

 

12.45

 

 

 

835,000

 

 

 

18,190,000

 

Total

 

 

6,810,000

 

 

$

13.09

 

 

 

6,810,000

 

 

 

18,190,000

 

 

(1) Includes commissions.

Item 3. Defaults Upon Senior Securities

 

None.

 

Item 4. Mine Safety Disclosures

 

Not applicable.

 

Item 5. Other Information

 

None.

 

60


 

Item 6. E xhibits

 

Exhibit No

 

Description

10.1

 

Fourth Amendment to the Encana (USA) Retirement Plan amended and restated effective March 14, 2014, dated as of May 17, 2018.

10.2

 

Alenco Inc. Deferred Compensation Plan amended and restated effective April 1, 2018, dated as of May 15, 2018.

31.1

 

Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934.

31.2

 

Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934.

32.1

 

Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350.

32.2

 

Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350.

101.INS

 

XBRL Instance Document.

101.SCH

 

XBRL Taxonomy Schema Document.

101.CAL

 

XBRL Calculation Linkbase Document.

101.DEF

 

XBRL Definition Linkbase Document.

101.LAB

 

XBRL Label Linkbase Document.

101.PRE

 

XBRL Presentation Linkbase Document.

 

 

61


 

SIGNAT URES

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.

 

ENCANA CORPORATION

 

By:

/s/ Sherri A. Brillon

 

 

Name:

 

Sherri A. Brillon

 

Title:

 

Executive Vice-President &

Chief Financial Officer

 

Dated: August 2, 2018

 

62

 

Exhibit 10.1

 

Fourth Amendment

to The

Encana (USA) Retirement Plan

(Amended and Restated Effective March 14, 2014)

 

1. Plan Sponsor :   Encana Services Company Ltd. (the “Plan Sponsor”).

 

2. Amendment of Plan :   Pursuant to the authority of the undersigned and the provisions of Section 13.1 of the Encana (USA) Retirement Plan (the “Plan”), the following Amendment to the Plan is adopted, effective as of the dates set forth below.

 

A. Effective June 1, 2018, Section 1.22 of the Plan is amended in its entirety as follows:

 

1.22 Eligible Employee means any Employee of the Employer, but does not include:

 

 

(a)

any Employee included in a unit of Employees covered by a collective bargaining agreement between the Employer and the Employee representative, the negotiation of which retirement benefits were the subject of good faith bargaining, unless the Employer and the Employee representative have agreed to allow such Employees to participate in the Plan pursuant to the terms of the collective bargaining agreement covering such Employees;

 

 

(b)

any Employee who is a nonresident alien who receives no earned income from the Employer that constitutes income from sources within the United States;

 

 

(c)

any Employee who is an expatriate covered by the Employer’s retirement plan in the Employee’s country of residence;

 

 

(d)

any Employee who is classified by the Employer as an intern; and

 

 

(e)

any Employee of an Employer with respect to any period prior to the date that the Employer has adopted this Plan with respect to its Employees.

 

Notwithstanding anything to the contrary in the Plan, the term Eligible Employee includes employees of Encana Corporation who are covered by a payroll services agreement between Encana Corporation and Alenco Inc.

 

B. Schedule A of the Plan is amended, effective June 1, 2018 to read as attached hereto.

 

3. Terms and Conditions of Plan :   Except for the above amendment, all terms and conditions of the Plan are unamended and shall remain in full force and effect.

 

 

 

 

Fourth Amendment to the Encana (USA) Retirement Plan

5/2018

1

 


 

3. Execution :   This Fourth Amendment has been executed on the date set forth below.

 

Encana Services Company Ltd.

Plan Sponsor

 

 

 

By:

 

/s/ Chris Casebolt

 

 

Chris Casebolt                          

Title:

 

Chair, Management Pension & Benefits Committee

Date:

 

05/17/2018

 

 

 

 

Fourth Amendment to the Encana (USA) Retirement Plan

5/2018

2

 


 

Encana (USA) Retirement Plan

 

Schedule A -
Participating Employers

 

Employer

Effective Date of Participation (if after the Effective Date of this amendment and restatement)

Encana Oil & Gas (USA) Inc.

n/a

Encana Corporation (for the limited purposes specified in Section 1.22)

June 1, 2018

 

* * * * End of Schedule A * * * *

 

 

 

 

Fourth Amendment to the Encana (USA) Retirement Plan

5/2018

3

 

 

Exhibit 10.2

 

ENCANA (USA)

 

DEFERRED COMPENSATION PLAN

 

[Amended and Restated Effective April 1, 2018]

 

WHEREAS , the Company acquired the Tom Brown, Inc. Deferred Compensation Plan dated as of March 1, 2001 (the “Prior Plan”) upon consummation of the Company’s purchase of Tom Brown, Inc., in May, 2004;

 

WHEREAS , the Company discontinued the Prior Plan and adopted the “Alenco Inc. Deferred Compensation Plan” effective December 1, 2004, as a nonqualified plan of deferred compensation for a select group of management or highly compensated employees (the “Plan”), including those participants in the Prior Plan (“Prior Plan Participants”) whose balances were transferred into the Plan upon its adoption;

 

WHEREAS , the Plan was amended and restated, effective January 1, 2009, to conform its terms to the requirements of Code Section 409A and the final Treasury regulations promulgated thereunder; and

 

WHEREAS , Encana Services Company Ltd. became the successor to Alenco, Inc., effective January 1, 2014, in connection with a reorganization of Encana Corporation and its affiliates; and

 

WHEREAS , the Company desires now to amend the Plan to: (1) recognize Encana Services Company Ltd. as the successor the Alenco Inc. and update Plan references accordingly (including revising the Plan name), (2) update the claims procedures under the Plan to comply with final regulations on disability claims procedures, (3) permit Participants to make elections to change time and form of distributions in accordance with Code Section 409A, and (4) permit certain employees of Encana Corporation to participate in the Plan.

 

NOW, THEREFORE , the Company amends and restates the Plan as follows, effective April 1, 2018;

 

ARTICLE I

GENERAL

 

1.1 Name of Plan .   The name of this plan is the “Encana (USA) Deferred Compensation Plan.”

 

1.2 Purpose .   The Plan has been established to provide future income to certain select management or highly compensated employees through voluntary deferrals of Compensation.

 

 


 

1.3 Effective Date .   The “Effective Date” of the Plan, the date as of which the Plan was established, is December 1, 2004, originally noted as January 1, 2005, which was the date the Plan became subject to Code Section 409A.

 

1.4 Company .   For purposes of this Plan, “Company” means Encana Services Company Ltd. (the successor employer to Alenco Inc.) and any successor employer thereof.

 

1.5 Participating Employers .   The Company is a “Participating Employer” in the Plan. Each subsidiary or affiliate of the Company that employs one or more Participants shall also be a Participating Employer. Each Participating Employer shall pay the cost of the benefits to which a Participant is entitled under the Plan attributable to service with that employer, and its share of the other expenses of the Plan, in each case in such amounts as are determined by the Company in its sole discretion. The Participating Employers are Encana Services Company Ltd., Encana Oil & Gas (USA) and, effective June 1, 2018, Encana Corporation (but only with respect to employees of Encana Corporation who are covered by a payroll services agreement between Encana Corporation and Alenco Inc.).

 

1.6 Construction and Applicable Law.   The Plan is intended to be an unfounded plan maintained primarily for the purpose of providing deferred compensation for a select group of management or highly compensated employees, within the meaning of Sections 201(2), 301(a)(3) and 401(a)(1) of ERISA. Further, the Plan is intended to comply with Code Section 409A, and the Plan shall be administered and construed consistent with said intent. This Plan also shall be governed and construed in accordance with the laws of the State of Colorado as applied to contracts executed and to be wholly performed within said state to the extent that such laws are not preempted by the laws of the United States of America.

 

ARTICLE II

DEFINITIONS

 

2.1 Accounts .   “Accounts” shall be established for each eligible Participant reflecting the amounts owed to the Participant or the Participant’s Beneficiary under the terms of this Plan. The following Accounts may be established for each Participant:

 

A. Retirement Account.   A Retirement Account shall be established to which shall be credited the amounts of Compensation deferred by the Participant under Sec. 4.1 (other than amounts the Participant elects to have credited to a Fixed Period Account), Employer Credits determined under Sec. 4.3, and the Investment Credits under Sec. 4.4 related to those deferrals and credits.

 

B. Fixed Period Account.   If the Participant so elects under Sec. 4.1D., a Fixed Period Account shall be established to which shall be credited the deferrals under Sec. 4.1 that the Participant elects to have credited to this type of Account and the Investment Credits under Sec. 4.4 related to those deferrals.

 

1. The Participant may elect to establish separate Fixed Period Accounts with different maturity dates.

 


 

2. The maturity date of each Fixed Period Account is January 1 st of a year specified by the Participant that is at least two years after the Plan Year with respect to which the election applies.

 

3. In no case shall an election or elections to establish Fixed Period Account(s) result in a payment under this Plan that is not objectively determined and payable on a determinable date.

 

The Company may maintain sub-accounts for a Participant within each Account to reflect the amount deferred or credited for each Plan Year and Investment Credits on that amount. Each Participant is always 100% vested in the amounts credited to his or her Accounts.

 

2.2 Beneficiary .   “Beneficiary” means the person or persons designated as such pursuant to the provisions of Sec. 5.5.

 

2.3 Board .   “Board” means the board of directors of the Company.

 

2.4 Code .   “Code” means the Internal Revenue Code of 1986, as amended from time to time, and any successor statute.

 

2.5 Compensation .   “Compensation” for a Plan Year means the cash compensation, and not any amounts denominated or paid in stock, for services performed during a Plan Year which is paid to the Participant by a Participating Employer. For purposes of this Plan, Compensation includes the following sub-categories:

 

A. Base Compensation means the Compensation which is paid on a regular periodic basis and classified as such by the Participating Employer.

 

B. Bonus Compensation means the Compensation which is paid under a bonus program of a Participating Employer. Bonus Compensation includes the following subcategories:

 

1. Performance-Based Bonus Compensation means any cash amounts paid to the Participant under a performance-based bonus program of a Participating Employer.  Performance-based bonus programs include only programs that are based on services performed over a period of at least 12 consecutive months, and under which payments are contingent on the satisfaction of preestablished organizational or individual performance criteria and not readily ascertainable at the time of the election. In compliance with Code Section 409A and the regulations thereunder, preestablished organization or individual performance criteria for Performance-Based Bonus Compensation shall (a) be established in writing no later than 90 days after the commencement of the 12 consecutive month period of service to which they relate, and (b) not be based upon any amount that will be paid either regardless of performance, or based on a level of performance that is substantially certain to be met at the time the criteria are established.

 

 


 

2. Other Bonus Compensation means the cash amounts paid to the Participant under a bonus program that does not qualify as Performance-Based Bonus Compensation.

 

The term “Bonus Compensation” refers hereafter to Performance-Based Bonus Compensation collectively.

 

2.6 Disability.    A participant shall be considered “Disabled” if (1) the participant is unable to engage in any substantial gainful activity by reason of any medically determinable physical or mental impairment which can be expected to result in death or can be expected to last for a continuous period of not less than 12 months, or (2) by reason of any medically determinable physical or mental impairment which can be expected to result in death or can be expected to last for a continuous period of not less than 12 months, the Participant is receiving income replacement benefits for a period of not less than 3 months under an accident and health plan covering employees of a Participating Employer.

 

2.7 Employer Credits .   “Employer Credits” are the credits allocable to the Participant’s Retirement Account pursuant to Sec. 4.3.

 

2.8 ERISA .   “ERISA” means the Employee Retirement Income Security Act of 1974, as amended from time to time, and any successor statute.

 

2.9 Investment Credits .   “Investment Credits” are the gains or losses allocable to Accounts of Participants under Sec. 4.4 based on the investment indexes elected by the Participant.

 

2.10 Participant .   A “Participant” is an individual described as such in Article III.

 

2.11 Plan Year .   A “Plan Year” is the 12 consecutive month period commencing on each January 1 and ending on the following December 31.

 

2.12 Qualified Employee .   “Qualified Employee” for a Plan Year means any select management or highly compensated employee of a Participating Employer who has been designated in writing by the President of the Company as eligible to Participate in the Plan for the current Plan Year.

 

2.13 Retirement .   “Retirement” means the Separation from Service of a Participant from the employ or service of a Participating Employer in accordance with the terms of the applicable qualified retirement plan, or if a Participant is not covered by such a retirement plan, the participant’s Separation from Service on or after the earliest to occur of the following:

 

A. the attainment of age 59 ½.

 

B. the attainment by the Participant of age 55 and 10 years of service (in accordance with the method of determining years of service adopted by the Participating Employer).

 


 

2.14 Separation from Service .   “Separation from Service” means the cessation of a Participant’s services as an employee of a Participating Employer for any reason including on account of death, Retirement or because the Participant is Disabled; provided, however, that transfer of employment between two companies that are included in a “controlled group” within the meaning of Code Sections 414 and 1563 will not constitute a Separation from Service for purposes of this Plan and provided, further, that the term “Separation from Service” shall be construed in a manner consistent with Code Section 409A and the regulations thereunder.

 

2.15 Unforeseeable Emergency .   “Unforeseeable Emergency” means a severe financial hardship to the Participant resulting from an illness or accident of the Participant, the Participant’s spouse, the Participant’s Beneficiary, or the Participant’s dependent (as defined in Code Section 152 (without regard to Section 151(b)(1), (b)(2), and (d)(1)(B)) of the Participant, loss of the Participant’s property due to casualty (including the need to rebuild a home followed by damage to a home not otherwise covered by insurance, for example, not as a result of a natural disaster), or other similar extraordinary and unforeseeable circumstances arising as a result of events beyond the control of the Participant.

 

2.16 Valuation Date .   “Valuation Date” means each date on which the Accounts of Participants are valued for purposes of this Plan. Valuation Dates shall include the last day of the Plan Year and such other dates as the Company determines are necessary or advisable for the administration of the Plan. Until the Company determines to use other Valuation Dates, the Valuation Dates are each business day on which the New York Stock Exchange is open for trading.

 

ARTICLE III

PARTICIPATION

 

3.1 Eligibility For Participation .   An employee shall become a Participant in the Plan on the date on which he or she becomes a Qualified Employee, and the effective date of an election by the individual to make deferrals under Sec. 4.1. However, the individual shall become a Participant on the date he or she first receives an Employer Credit under Sec. 4.3, if earlier.

 

3.2 Duration Of Participation .   An employee who becomes a Participant shall continue to be eligible to make elections under Sec. 4.1 thereafter, subject to the following:

 

A. The Participant’s deferrals shall cease on the date of the Participant’s Separation from Service.

 

B. No deferrals under Sec. 4.1 shall be made from any Compensation that is payable to the Participant after the earliest of the dates specified in Subsection A. unless he or she again meets the requirements for being a Qualified Employee for a subsequent Plan Year. However, an individual shall continue to be a Participant for purposes of the provisions of the plan other than Sec. 4.1 or Sec. 4.3 until the date all of his or her Accounts have been distributed.

 

 


 

3.3 Prior Plan Participants .    Notwithstanding anything to the contrary, all accounts of Prior Plan Participants shall be administered pursuant to the terms and conditions of this Plan from and after the date of its adoption.

 

3.4 No Guarantee of Employment .   Participation in the Plan does not constitute a guarantee or contract of employment with any Participating Employer. Such participation shall in no way interfere with any rights Participating Employers would have in the absence of such participation to determine the duration of the employee’s employment.

 

ARTICLE INDIVIDUAL

DEFERRED COMPENSATION AND CREDITS TO ACCOUNTS

 

4.1 Election to Defer Compensation .   A Qualified Employee may elect to have part of the Compensation for a Plan Year credited to his or her Accounts rather than being paid in cash. The Compensation otherwise payable to a Participant who elects to defer compensation under this section shall be reduced by the percentage or amount so elected, subject to the following:

 

A. Elections shall be written and made in the manner specified by the Company (which may include an electronic form). Elections for each Plan Year must be completed during the election period specified by the Company for such Plan Year, which period must end on or prior to December 31 of the previous year for Base Compensation elections and for Other Bonus Compensation elections, and no later than June 30 of the current Plan Year for Performance-Based Bonus Compensation elections, subject to the following:

 

1. In the first year in which an individual becomes a Qualifi ed Employee, such individual may make an election to defer Compensation with respect to services to be performed subsequent to the election within 30 days following the date the individual becomes a Qualified Employee, and the election will be effective as of the first day of the first pay period commencing after the election is made.

 

2. An election to defer Performance-Based Bonus Compensation shall be available only to Participants who perform services continuously from the later of beginning of the applicable performance period or the date the performance period criteria are established through the date an election is made under this Subsection A, and whose election to defer such Performance-Based Bonus Compensation is made before the Compensation is readily ascertainable. In general, any amount that is both calculable and substantially certain to be paid, as defined in Treasury Reg. Section 1.409A-2(a)(8), is treated as readily ascertainable.

 

B. The Participant may elect to defer any whole percent of Base Compensation payable during each pay period, but not more than 50% of Base Compensation.

 

 


 

C. The Participant may elect to defer any whole percent (up to and including 100%) of any payment of Bonus Compensation Notwithstanding the foregoing, the Company may, without amending the Plan, limit the maximum amount of Bonus Compensation that may be deferred under the Plan.

 

D. The Participant’s election for each Plan Year shall specify the portion of the amount deferred during that year that is to be allocated to the Participant’s Retirement Account and the portion that is to be allocated to the Participant’s Fixed Period Account. The election must be stated in whole percents and must total 100%. If the Participant fails to make an adequate election under this subsection, the entire amount deferred (or the portion of the deferral which is not specifically allocated to a Fixed Period Account, if applicable) shall be allocated to the Participant’s Retirement Account.

 

E. The deferred compensation credited under the Plan on behalf of a Participant for a Plan Year shall be allocated to the Accounts of the Participant as of the date that the Base Compensation or Bonus Compensation would otherwise have been paid to the Participant in cash.

 

F. The Participant must make a separate election with the Company for each Plan Year for which elective deferrals under this Section 4.1 are to be made under this Plan. An election for a Plan Year shall become irrevocable on the last day of the preceding Plan Year for Base Compensation and Other Bonus Compensation elections and no later than June 30 of the Current Plan Year for Performance-Based Bonus Compensation, as the Company may require. Elections will not carry over into subsequent Plan Years.

 

G. Notwithstanding anything in this Section 4.1 to the contrary, elections to defer Performance-Based Bonus Compensation and Other Bonus Compensation attributable to services performed during the year ended December 31, 2004, may be made on or before December 31, 2004. Pursuant to Treasury Regulation Section 1.409A-6(a)(ii), the Company explicitly identifies such amounts as amounts deferred under the Plan with respect to the 2004 calendar year and as subject in all respects to Code Section 409A commencing January 1, 2005.

 

4.2 Election as to Form of Payment .   The Participant shall make an election as to how the balance in the Participant’s Accounts will be distributed. The election must be in written and made in the manner specified by the Company (which may include an electronic form). The Participant may elect to have the Participant’s balance distributed in (1) a lump sum, or (2) in annual installments for any number of years up to 10 years. If the Participant fails to make an election for an Account as provided herein, then the Participant will be deemed to have elected the lump sum distribution option for such Account. All elections as to form of payment shall be irrevocable. The time for making such elections is as follows:

 

A. With respect to the Participant’s Retirement Account, the Participant shall elect the form of payment at the time the Participant first enrolls in the Plan pursuant to Sec. 4.1.

 


 

B. With respect to the Participant’s Fixed Period Account, the Participant shall elect the form of payment at the time the Participant first elects to defer Compensation into such Fixed Period Account.

 

4.3 Employer Credits .   The Board, or its authorized delegate, may determine in its sole discretion that a credit will be made by the Company or other Participating Employer to the Retirement Account of one or more eligible Participants for a particular Plan Year. If a credit is to be made for a particular Participant for a Plan Year, the Board, or its authorized delegate, will determine the amount of the credit, the date or dates on which the amount will be credited to the Participant’s Retirement Account, and any rules the Participant must satisfy to receive the credit. Such rules may include, but are not limited to, requirements that the Participant must be employed by a Participating Employer on a particular date during or after the end of the Plan Year, that the Participant must complete a certain number of hours of service during the Plan Year, or that the Participant must meet certain performance standards for the year.

 

4.4 Investment Credits And Valuation Of Accounts .   The Accounts of each Participant will be adjusted as of each Valuation Date to reflect Investment Credits, deferrals allocated to the Account under Sec. 4.1, Employer Credits allocated under Sec. 4.3, and distributions from the Account under Article V, in each case since the previous Valuation Date, subject to the following:

 

A. Investment Credits will be based on the investment index or indexes selected by the Participant to measure the deemed rate of investment return on his or her Accounts. The investment indexes will include such investment options as the Company makes available under this Plan from time to time. The Company may in its sole discretion add additional options or delete existing options available to a Participant at any time, provided the Participant has been notified as described in Sec. 7.1. Notwithstanding anything in the Plan to the contrary, the Company shall be under no obligation to purchase any investments used for determining Investment Credits. The investment indexes are used solely for the recordkeeping purpose of measuring gains and losses on each Participant’s Accounts, and the Participant’s Accounts are not actually being invested in the indexes.

 

B. All investment elections shall be written and made in the form specified by the Company (which may include an electronic form) and provided to the Company or with such agent or agents as may be designated from time to time by the Company for this purpose. Subject to subsection A. above, each investment election shall remain in effect until a new election is filed by the Participant.

 

C. An initial investment election shall be filed by the Participant when an Account is first established for the Participant. Thereafter, the Participant may change the investment indexes for existing Account balances and future credits effective as of any Valuation Date, provided the change is filed prior to the deadline that may be established by the Company or its designated agent from time to time for the desired effective date. All investment elections must be expressed in whole percent increments for each option.

 


 

D. A Participant may file separate investment elections for his or her Retirement Account and all Fixed Period Accounts, and may also file separate investment elections for the existing Account balance and for future amounts to be credited to each Account. If the Participant fails to file an effective investment election for all or part of an Account, that amount shall be credited with Investment Credits according the yield on a default investment option designated by the Company from time to time.

 

E. If distributions are to be made in installments following the death of a Participant, each Beneficiary shall have the same right to make investment elections for the portion of the Participant’s Accounts held on behalf of the Beneficiary as the Participant had prior to death.

 

F. All investment elections shall be in accordance with such rules and regulations as the Company or its designated agent may establish from time to time. The Company or its agent may also establish such procedures for the valuation of Accounts as the Company or its agent determines in its sole discretion will reasonably reflect the period of time amounts were credited to each Account.

 

G. Notwithstanding the foregoing, the Company may modify or disregard an investment election filed by a Participant to the extent the Company determines that such action is necessary to comply with the terms of this Plan or to avoid adverse tax consequences to the Participant or any Participating Employer. The Company may delay the implementation of Participant investment elections under this section to a date later than January 1, 2005 in which case the Participant’s Accounts will be credited during the period of the delay with Investment Credits at a rate or index established by the Company for this purpose prior to January 1, 2005.

 

4.5 Unsecured Obligations .   A Participant’s credits in his or her Accounts shall be an unsecured obligation of the Participating Employer for which the Participant is or was employed. Each Participant or Beneficiary is only a general creditor of the Participating Employer with respect to his or her Accounts. Accounts are maintained for recordkeeping purposes only. Notwithstanding the foregoing, obligations to pay benefits under this Plan may be satisfied by distributions from a grantor trust created by the Company in his sole discretion for such purpose. Each Participant shall cooperate with the Company and shall execute any documents or submit to any physical examination reasonably required by the Company in connection with the administration of the Plan.

 

 


 

4.6 Changes in Time or Form of Distribution .    A Participant may make a subsequent election to change the time and/or form of a distribution initially specified under Sec. 4.1 and Sec. 4.2 with respect to one or more Fixed Period Accounts, but only if the following conditions are satisfied:

 

(1) the election may not take effect until at least twelve months after the date on which the election is made;

 

(2) a distribution may not be made earlier than at least five years from the date the distribution would have otherwise been made;

 

(3) t he election must be made at least twelve months before the date of the first scheduled distribution;

 

(4) t he election may not result in an impermissible acceleration of payment prohibited under Code Section 409A and applicable guidance thereunder; and

 

(5) the revised distribution form may not consist of more than 10 annual installments.

 

An election to change the time and/or form of distribution shall be (1) written and made in the manner specified by the Company (which may include an electronic form), and (2) made in accordance with such additional rules and procedures as established by the Company and in accordance with Code Section 409A.  

 

 

ARTICLE V

DISTRIBUTION OF ACCOUNTS

 

5.1 Distribution Of Accounts .   Except as otherwise provided, a Participant’s Accounts will be distributed commencing upon the first to occur of the following in the form elected by the Participant:

 

A. Separation from Service other than Upon Retirement, Death or Disability.   If a Participant has a Separation from Service prior to commencing distributions from an Account other than on account of Retirement, death or because the Participant is Disabled, then distributions from such Account will commence as soon as administratively feasible in the first Plan Year following the Participant’s Separation from Service in the manner elected by the Participant, except that the installment period shall be 5 years if the Participant elected installment payments of 5 years or more.

 

B. Retirement or Disability.   If the Participant Separates from Service on account of Retirement or because the Participant is Disabled, then distributions will commence as soon as administratively feasible in the first Plan Year following the Participant’s Separation from Service in the manner elected by the Participant.

 

 


 

C. Death Prior to Commencement.    If the Participant dies prior to commencing distributions from an Account, distributions to the Beneficiary or Beneficiaries will commence within 90 days after the last day of the month in which the Participant’s death occurred in the manner elected by the Participant.

 

D. Death Following Commencement.   If the Participant dies after beginning to receive installment payments, the Beneficiary or Beneficiaries shall receive the remaining installment payments at the same times as the Participant would have received them if he or she had survived.

 

E. Matu rity of a Fixed Period Account.   In the case of a Fixed Period Account, distributions will commence upon the earlier of the times specified in subsections A. through D. above or upon the maturity date of such Fixed Period Account. Distributions will be made in the manner elected by the Participant; provided that Distributions commencing pursuant to subsection A. above (upon Separation from Service other than on account of Retirement, death or Disability) will be made in the manner elected by the Participant, except that the installment period shall be 5 years if the Participant elected installment payments of 5 years or more.

 

5.2 Distribution of Lump Sums .   If a Participant’s Account is to be distributed in a lump sum, the amount distributed will be the value of the Account on last Valuation Date preceding the date of the distribution.

 

5.3 Administration of Accounts during Installment Period .   If payments from an Account are to be made in installments, then the annual amount paid in each year will be equal to the value of the Account as of the last Valuation Date preceding the date the first installment is to be made, divided by the number of installments that remain subject to the following:

 

A. The Account will continue to be adjusted for Investment Credits pursuant to Sec. 4.4 during the installment period.

 

B. Installment payments will cease when the balance of the Account is equal to $0.

 

C. The payment for the final year of installments will include the entire balance remaining in the Account at that time.

 

Each installment payment after the first payment will be paid on the anniversary date of the first such installment.

 

5.4 Distributions to “Specified Employees” Upon Separation from Service .   Notwithstanding anything to the contrary herein, in the case of any Participant who is a Specified Employee, distributions to such Participant shall not commence before the date which is 6 months after the date of such Participant’s Separation from Service (that is, no earlier than the first day of the seventh month following the date of the Participant’s Separation from Service). In the case of any payments pursuant to an installment method of payment any installment payments for a Participant who is a

 


 

Specified Employee following such Participant’s initial payment following Separation from Service shall be made on the anniversary date of the first installment regardless of the date of such Participant’s Separation from Service. For purposes of this Sec. 5.4, the term “Specified Employee” means a key employee within the meaning of Code Section 409A(a)(2)(B)(i). This paragraph shall not apply in the case of distributions upon the death of a Specified Employee.

 

5.5 Beneficiary Designation .   Each Participant shall have the right, at any time, to designate any person or persons as Beneficiary or Beneficiaries to whom payments under this Plan shall be made in the event of the Participant’s death prior to complete distribution of the amount credited to the Participant’s Accounts. Each Participant shall have the right to change his or her Beneficiary designation at any time. Each Beneficiary designation shall become effective only when filed in writing with the Company during the Participant’s life in the manner prescribed by or approved by the Company (which may include an electronic form). The rights of each Beneficiary shall be subject to the terms and conditions specified on the designation form to the extent consistent with the terms of the Plan. If a Participant fails to designate a Beneficiary as provided above, or if all designated Beneficiaries predecease the Participant, then the Beneficiary shall be the Participant’s estate.

 

5.6 Distributions For Unforeseeable Emergency .   Notwithstanding the foregoing sections of this Article V, the Company in its sole discretion may approve a written request by a Participant for a withdrawal from the Participant’s Accounts due to an Unforeseeable Emergency. Any amount distributed pursuant to this Sec. 5.6 shall not exceed the amount necessary to satisfy such Unforeseeable Emergency plus amounts necessary to pay taxes reasonably anticipated as a result of the distribution, after taking into account the extent to which such hardship is or may be relived through reimbursement or compensation by insurance or otherwise or by liquidation of such assets (to the extent liquidation of such assets would not itself cause a severe financial hardship).

 

5.7 Payment Of Small Benefits .   Notwithstanding the foregoing provisions of this Article V, if the total balance of the Participant’s Accounts upon his Separation from Service is less than $10,000, the Company shall pay the entire balance in a single lump sum on a date determined by the Company as soon as administratively feasible following the Participant’s Separation from Service, but in no event later than 2 ½ months after the Plan Year in which such Separation from Service occurs, except that in the case of a Specified Employee the distribution shall not be made before the date which is 6 months after the date of such Participant’s Separation from Service, subject to any exceptions or conditions provided under Sec. 5.4.

 

5.8 Withholding And Taxes .   The benefits payable under this Plan shall be subject to the deduction of any federal, state, or local income taxes or other taxes which are required to be withheld from such payments by applicable laws and regulations. Any Social Security (FICA) taxes which must be withheld prior to the distribution benefits to the Participant shall be withheld from the amounts deferred, or from the Participant’s other compensation, as determined by the Company. The Company provides no assurances or guarantees regarding the tax treatment of amounts deferred or payments made under this Plan. Each Participant is solely responsible for any applicable income, excise and other taxes, penalties or interest (including any excise tax under Code Section 4999).

 


 

5.9 Delay of Payments Subject to Code Section 162(m) .    Notwithstanding anything in this Article V to the contrary, a payment otherwise payable under this Plan shall be delayed if the Company reasonably anticipates that the Company’s deduction with respect to such payment otherwise would be eliminated or limited by application of Code Section 162(m). In the event of such delay in payment, actual payment shall be made at the earliest date the Company anticipates that the deduction of the payment amount will not be limited or eliminated by the application of Code Section 162(m) or the calendar year in which the Participant experiences a Separation from Service, if sooner.

 

ARTICLE VI

ADMINISTRATION AND CLAIMS PROCEDURES

 

6.1 Administration By The Company .   The Company, or its authorized delegate, shall administer the Plan, shall establish, adopt, or revise such rules and regulations as it may deem necessary or advisable for the administration of the Plan, and shall have discretionary authority to interpret the provisions of the Plan. The interpretations of the Company shall be conclusive on all parties.

 

6.2 Claims Procedure .   Any person who believes he or she is being denied any rights or benefits under the Plan may file a claim in writing with the Company. If the claim is denied (in whole or part), the Company will notify the claimant of its decision in writing. The notification will be written in a manner intended to be understood by the claimant and will contain [i] the specific reasons for the adverse determination, [ii] reference to the specific Plan provisions on which the determination is based, [iii] a description of additional material or information necessary for the claimant to perfect the claim, [individual] information as to the steps to be taken if the claimant wishes to submit a request for review, and [v] a statement of the claimant’s right to bring a civil action under ERISA Section 502(a) if the claim is denied on appeal. In the case of disability benefits, the Company’s written notification of any adverse benefit determination will be provided in a culturally and linguistically appropriate manner and must contain the following information [vi] if an internal rule, guideline, protocol, or other similar criterion was relied upon in making the adverse determination: either the specific rule, guideline, protocol, or other similar criterion, or a statement that such rule, guideline, protocol, or other similar criterion was relied upon in making the adverse determination and that a copy of the rule, guideline, protocol, or other similar criterion will be provided to the claimant free of charge upon request, [vii] a discussion of the decision, including an explanation of the basis for disagreeing with or not following: the views provided by the claimant’s health care or vocation professionals who treated and evaluated the claimant; the views of medical or vocational experts whose advice was obtained by the plan, regardless of whether the advice was relied upon in making the benefit determination; and any disability determination made by the Social Security Administration, [viii] if the adverse benefit determination is based on medical necessity, experimental treatment, or similar exclusion or limit, either an explanation of the scientific or clinical judgement for the determination, applying the terms of the plan to the claimant’s medical circumstances, or a statement that an explanation will be provided free of charge upon request, and [ix] a statement that the claimant is entitled to receive, upon request and free of charge, reasonable access to, and copies of, all documents, records, and other information relevant to the claim for benefits.

 


 

The notification will be given within 90 days after the claim is received by the Company (or within 180 days, if special circumstances require an extension of time for processing the claim, and if written notice of the extension and circumstances is given to the claimant within the initial 90 day period). If notification is not given within this period, the claim will be considered denied as of the last day of such period and the claimant may request review of the claim. In the case of a claim for disability benefits, then instead of the above, the Company will provide the claimant with written notification of the Plan’s adverse benefit determination within a reasonable period of time, but not later than 45 days after receipt of the claim by the Company. The disability notification period may be extended by the Company for up to 30 days, provided that the Company both determines that such an extension is necessary due to matters beyond the control of the Company and notifies the claimant, prior to the expiration of the initial 45-day period, of the circumstances requiring the extension of time and the date by which the Company expects to render a decision. If, prior to the end of the first 30-day extension period the Company determines that, due to matters beyond its control, a decision on the disability benefit cannot be rendered within that extension period, the period for making the determination may be extended for up to an additional 30 days, provided that the Company notifies the claimant, prior to the expiration of the first 30-day extension period, of the circumstances requiring the extension and the date as of which the Company expects to render a decision. In the case of any such extension relating to a disability benefit, the notice of extension will specifically explain the standards on which entitlement to a benefit is based, the unresolved issues that prevent a decision on the claim, and the additional information needed to resolve those issues, and the claimant will be afforded at least 45 days within which to provide the specified information.

 

6.3 Review Procedure .   If a claim is denied in whole or in part, or if it is deemed denied, the claimant has 60 days after receipt of the written notice of denial of the claim, or 60 days after the claim is deemed denied, in which to file a written request with the Company that it conduct a review of the claim. If the claim is for disability benefits, then the request for review must be filed within 180 days after receipt of the denial or after the claim is deemed denied. In connection with the claimant’s appeal of the denial of a benefit, the claimant may review pertinent documents and may submit issues and comments in writing. The claimant will be provided, upon request and free of charge, reasonable access to, and copies of, all documents, records, and other information relevant to the claim for benefits. The claimant will have a reasonable opportunity for full and fair review of the claim and adverse determination. This review will take into account all comments, documents, records, and other information submitted by the claimant relating to the claim, without regard to whether such information was submitted or considered in the initial benefit determination. In addition, if the claim is for disability benefits, then the following rules apply: (a) The claim will be reviewed without deference to the initial adverse benefit determination and the review will be conducted by an appropriate named fiduciary of the Plan who is neither an individual who made the adverse benefit determination that is the subject of the appeal, nor the subordinate of such individual (and who shall be designated by the Company). (b) In deciding an appeal of any adverse benefit determination that is based in whole or part on medical judgment, the appropriate named fiduciary will consult with a health care professional who has appropriate training and experience in the field of medicine involved in the medical judgment. (c) Any medical or vocational experts whose advise was obtained on behalf of

 


 

the Plan in connection with the adverse benefit determination will be identified, without regard to whether the advice was relied upon in making the benefit determination. (d) The health care professional engaged for purposes of a consultation under (b) above will be an individual who is neither an individual who was consulted in connection with the adverse benefit determination that is the subject of the appeal, nor the subordinate of any such individual.   In addition, i n the case of a claim regarding d isability, before a final adverse benefit determination is made, the a dministrator will provide the claimant, free of charge, with any new or additional evidence or rationale considered, relied upon, or generated by the plan in connection with the claim as soon as possible and sufficiently in advance of the final notice to give the claimant a reasonable opportunity to respond prior to that date .

 

The claimant will be provided with written notification of the Plan’s benefit determination on review. The notification must be provided to the claimant not later than 60 days after the receipt of the claimant’s request for review, unless special circumstances (such as the need to hold a hearing, if necessary) require an extension of time for processing, in which case the 60 day period may be extended for a period of 60 days from the end of the initial period. If the claim relates to disability benefits, then 45 days will apply instead of 60 days in the preceding sentences. The claimant will be notified in writing of any extension. In the case of an adverse benefit determination on review, the notification will set forth [i] specific reasons for the adverse determination, [ii] reference to the specific Plan provisions on which the benefit determination is based, [iii] a statement that the claimant is entitled to receive, upon request and free of charge, reasonable access to, and copies of, all documents, records, and other information relevant to the claim, and [iv] a statement of the claimant’s right to bring an action under ERISA Section 502(a) and any applicable contractual limitations period that applies to the claimant's right to bring such an action. In the case of disability benefits, the Company’s written notification of any adverse benefit determination will be provided in a culturally and linguistically appropriate manner and must contain the following information [v] if an internal rule, guideline, protocol, or other similar criterion was relied upon in making the adverse determination: either the specific rule, guideline, protocol, or other similar criterion, or a statement that such rule, guideline, protocol, or other similar criterion was relied upon in making the adverse determination and that a copy of the rule, guideline, protocol, or other similar criterion will be provided to the claimant free of charge upon request, [iv] a discussion of the decision, including an explanation of the basis for disagreeing with or not following: the views provided by the claimant’s health care or vocation professionals who treated and evaluated the claimant; the views of medical or vocational experts whose advice was obtained by the plan, regardless of whether the advice was relied upon in making the benefit determination; and any disability determination made by the Social Security Administration, [v] if the adverse benefit determination is based on medical necessity, experimental treatment, or similar exclusion or limit, either an explanation of the scientific or clinical judgement for the determination, applying the terms of the plan to the claimant’s medical circumstances, or a statement that an explanation will be provided free of charge upon request.

 

 


 

ARTICLE VII

AMENDMENT AND TERMINATION

 

7.1 Amendment .   The Plan may be amended in whole or in part at any time for a reason by action of the Board, or by action of any person to whom that authority has been delegated by the Board. No amendment shall decrease the benefits under the Plan which have accrued prior to the date such amendment is adopted. However, the Company may modify the investment index options under Sec. 4.4 to be used to determine Investment Credits for a Participant’s Accounts commencing as of a date specified by the Company, but not sooner than 30 days after the date a notice of the change is either mailed or hand-delivered to the Participant.

 

7.2 Termination Of Plan .   The Company, by action of the Board, may terminate the Plan at any time. After such termination, no employee shall become a Participant, and no further amounts shall be credited pursuant to Sec. 4.1 or Sec. 4.3 to Accounts of Participants. Thereafter, the amounts credited to the Accounts of Participants will continue to be credited with Investment Credits pursuant to Section 4.4 and distributed in accordance with Article V.

 

ARTICLE VIII

MISCELLANEOUS

 

8.1 Benefits May Not Be Assigned Or Alienated .   Neither a Participant nor any Beneficiary shall have the right to sell, assign, transfer, encumber or otherwise convey any right to receive any payment hereunder. No part of the amounts payable hereunder shall be subject to seizure or sequestration for the payment of any debts or judgments owed by a Participant or any other person; provided however, that the Company may offset the obligations to the Participant or the Participant’s Beneficiary hereunder by any debt of the Participant to the Company or any other Participating Employer where such debt is incurred in the ordinary course of the business relationship between the Participant and the Company; and provided further, that (i) the entire amount of reduction in any taxable year of the Company does not exceed $5,000 and (ii) the reduction is made at the same time and in the same amount as the debt otherwise would have been due and collected from the Participant.

 

8.2 Right to Limit Deferrals .   Notwithstanding anything to the contrary, the Company and any Participating Employer reserves the right to limit the aggregate amount of deferrals made by Participants during a Plan year to $5,000,000, or such other amount specified in subsection 5(e) of Rule 701 of Regulation E of the Securities Act of 1933 if the Company or such Participating Employer determines that it is desirable to do so. The manner of limiting deferrals under this paragraph will be determined by the Company or such Participating Employer as the case may be. Such deferral limit for any given Plan Year shall be imposed prior to the date deferrals are required to be or become irrevocable for that Plan Year under Code Section 409A, the regulations thereunder, and Article IV of this Plan.

 

8.3 Incompetency .   Every person receiving or claiming benefits under this Plan shall be conclusively presumed to be mentally competent until the date on which the Company received a written notice in a form and manner acceptable to the Company that

 


 

such person is incompetent and that a guardian, conservator or other person legally vested with the care of his or her estate has been appointed. In such event, the Company may direct payments of benefits to such guardian, conservator or other person legally vested with the care of the person’s estate and any such payments so made shall be a complete discharge of the Participating Employers to the extent so made.

 

8.4 Successor Employer .   The Plan shall be binding on the Company and its assigns, each Participating Employer and its assigns, and any entity that succeeds to the business of the Company or another Participating Employer through merger, consolidation, or acquisition of all or substantially all the Company’s assets or another Participating Employer’s assets.

 

8.5 Notices .   Notices required by this Plan to be given to the Company or a Participant shall be in writing and shall be considered to have been duly given or served if personally delivered, or sent by first class, certified or registered mail.

 

8.6 Severability .   The invalidity or partial invalidity of any portion of this Plan shall not invalidate the remainder thereof, and said remainder shall remain in full force and effect.

 

8.7 Headings .   Headings at the beginning of articles and sections hereof are for convenience of reference, shall not be considered a part of the text of the Plan, and shall not influence its construction.

 

8.8 Capitalized Definitions .   Capitalized terms used in the Plan shall have their meaning as defined in the Plan unless the context clearly indicates to the contrary.

 

8.9 Gender .   Any references to the masculine gender include the feminine and vice versa.

 

8.10 Use Of Compounds Of Word “Here” .   Use of the words “hereof”, “herein”, “hereunder”, or similar compounds of the word “here” shall mean and refer to the entire Plan unless the context clearly indicates to the contrary.

 

8.11 Construed As A Whole .   The provisions of the Plan shall be construed as a whole in such manner as to carry out the provisions hereof and shall not be construed separately without relation to the context.

 

 

 


 

8.12 Code Section 409A .   It is intended that the Plan comply with the provisions of Code Section 409A. The Plan and each d eferral a greement will be administered in a manner consistent with this intent. Installment payment s made under the Plan will be treated as the entitlement to a “single payment” for purposes of Code Section 409A. A Participant is solely responsible and liable for the satisfaction of all taxes and penalties that may be imposed on a Participant in connection with the Plan (including any taxes and penalties under Code Section 409A), and the Company has no obligation to indemnify or otherwise hold a Participant harmless from any or all of such taxes or penalties.

 

Encana Services Company Ltd.

 

 

 

By:

 

/s/ Michael Williams

 

 

Michael Williams

Title:

 

Chair, Management Pension & Benefits Committee

Date:

 

May 15, 2018

 

10945473_3

Exhibit 31.1

CERTIFICATION PURSUANT TO RULE 13a-14(a) OR 15d-14(a) OF THE

SECURITIES EXCHANGE ACT OF 1934, AS ADOPTED PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Douglas J. Suttles, certify that:

1.

I have reviewed this quarterly report on Form 10-Q of Encana Corporation;

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.

The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

 

a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

 

b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

 

c)

Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

 

d)

Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.

The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

 

a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

 

b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Dated: August 2, 2018

/s/ Douglas J. Suttles

 

Douglas J. Suttles
President & Chief Executive Officer

(Principal Executive Officer)

Exhibit 31.2

CERTIFICATION PURSUANT TO RULE 13a-14(a) OR 15d-14(a) OF THE

SECURITIES EXCHANGE ACT OF 1934, AS ADOPTED PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Sherri A. Brillon, certify that:

1.

I have reviewed this quarterly report on Form 10-Q of Encana Corporation;

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.

The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

 

a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

 

b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

 

c)

Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

 

d)

Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.

The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

 

a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

 

b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Dated: August 2, 2018

/s/ Sherri A. Brillon

Sherri A. Brillon
Executive Vice-President & Chief Financial Officer
(Principal Financial Officer)

Exhibit 32.1

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED

PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Encana Corporation (the “Company”) on Form 10-Q for the period ended June 30, 2018 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Douglas J. Suttles, President & Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:

 

(1)

The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

 

(2)

The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.  

By: /s/ Douglas J. Suttles

 

Douglas J. Suttles

President & Chief Executive Officer

 

Dated: August 2, 2018

Exhibit 32.2

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED

PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Encana Corporation (the “Company”) on Form 10-Q for the period ended June 30, 2018 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Sherri A. Brillon, Executive Vice-President & Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:

 

(1)

The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

 

(2)

The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.  

By: /s/ Sherri A. Brillon

 

Sherri A. Brillon

Executive Vice-President & Chief Financial Officer

 

Dated: August 2, 2018