ENCANA CORP (Form: 8-K, Received: 02/28/2019 12:23:30)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d)

of The Securities Exchange Act of 1934

February 28, 2019

Date of Report (Date of earliest event reported)

Encana Corporation

(Exact name of registrant as specified in its charter)

Canada

1-15226

98-0355077

(State or other jurisdiction

of incorporation)

(Commission

File Number)

(IRS Employer

Identification No.)

Suite 4400, 500 Centre Street SE, PO Box 2850

Calgary, Alberta, Canada, T2P 2S5

(Address of principal executive offices) (Zip Code)

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

Not Applicable

(Former name or former address, if changed since last report.)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

☐	Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

☐	Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

☐	Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

☐	Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (§240.12b-2 of this chapter).

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. ☐

ITEM 8.01

Other Events.

As previously announced, on February 13, 2019, Encana Corporation (“Encana”), completed its previously announced strategic combination with Newfield Exploration Company, a Delaware corporation (“Newfield”), pursuant to an Agreement and Plan of Merger (the “Merger Agreement”), dated as of October 31, 2018, by and among Encana, Neapolitan Merger Corp., a Delaware corporation and an indirect, wholly-owned subsidiary of Encana (“Merger Sub”), and Newfield. Pursuant to the Merger Agreement, Merger Sub merged with and into Newfield, with Newfield surviving the merger as an indirect, wholly-owned subsidiary of Encana (the “Merger”). The Report on Form 8-K filed by Encana with the Securities and Exchange Commission (the “SEC”) on February 20, 2019 and the definitive joint proxy statement/prospectus filed by Encana with the SEC pursuant to Rule 424(b)(3) under the Securities Act of 1933 on January 8, 2019 contain additional information about the Merger.

The audited financial statements of Newfield, and the related report of independent registered public accounting firm, unaudited pro forma condensed combined financial statements, and the related notes, and supplemental pro forma combined oil, natural gas liquids and natural gas reserves information, in each case, referred to in Item 9.01 are incorporated by reference into this Item 8.01.

ITEM 9.01

Financial Statements and Exhibits.

(a) Financial Statements

The audited consolidated balance sheet of Newfield, as of December 31, 2018 and December 31, 2017, the consolidated statements of operations and comprehensive income, the consolidated statements of cash flows and the consolidated statement of stockholders’ equity of Newfield, for the years ended December 31, 2018, 2017 and 2016, and the notes related thereto, are included as Exhibit 99.2 hereto and are incorporated by reference into this Item 9.01(a).

The Report of Independent Registered Public Accounting Firm, issued by PricewaterhouseCoopers LLP, dated February 28, 2019, relating to the consolidated financial statements of Newfield is included as Exhibit 99.1 hereto and is incorporated by reference into this Item 9.01(a).

(b) Pro Forma Information

The unaudited pro forma condensed combined balance sheet as of December 31, 2018 gives effect to the Merger as if the Merger had been completed on December 31, 2018. The unaudited pro forma condensed combined statement of earnings for the year ended December 31, 2018 gives effect to the Merger as if the Merger had been completed on January 1, 2018. The pro forma financial information, and the related notes thereto, are included as Exhibit 99.3 hereto and are incorporated by reference into this Item 9.01(b).

The supplemental pro forma combined oil and natural gas reserves information as of December 31, 2018 gives effect to the Merger as if the Merger had been completed on January 1, 2018, is included as Exhibit 99.4 hereto and is incorporated by reference into this Item 9.01(b).

(d) Exhibits


Exhibit No.		Exhibit Description

Exhibit 23.1		Consent of PricewaterhouseCoopers LLP.

Exhibit 23.2		Consent of Ryder Scott Company, L.P.

Exhibit 23.3		Consent of DeGolyer and MacNaughton.

Exhibit 23.4		Consent of McDaniel & Associates Consultants Ltd.



Exhibit 23.5		Consent of Netherland, Sewell & Associates, Inc.

Exhibit 99.1		Report of Independent Registered Public Accounting Firm, issued by PricewaterhouseCoopers LLP, dated February 28, 2019, relating to the consolidated financial statements of Newfield.

Exhibit 99.2		The audited consolidated balance sheet of Newfield, as of December 31, 2018 and December 31, 2017, and the consolidated statements of operations and comprehensive income, consolidated statements of cash flows and consolidated statements of stockholders’ equity of Newfield, for the years ended December 31, 2018, 2017 and 2016, and the notes related thereto.

Exhibit 99.3		The unaudited pro forma condensed combined balance sheet as of December 31, 2018 and the unaudited pro forma condensed combined statement of earnings for the year ended December 31, 2018.

Exhibit 99.4		Supplemental pro forma combined oil and natural gas reserves information as of December 31, 2018.

Exhibit 99.5		Report of Ryder Scott Company, L.P.

Exhibit 99.6		Report of DeGolyer and MacNaughton.

Exhibit 99.7		Report of McDaniel & Associates Consultants Ltd. (incorporated by reference to Exhibit 99.1 to Encana’s Annual Report on Form 10-K filed on February 28, 2019, SEC File No. 001-15226).

Exhibit 99.8		Report of Netherland, Sewell & Associates, Inc. (incorporated by reference to Exhibit 99.2 to Encana’s Annual Report on Form 10-K filed on February 28, 2019, SEC File No. 001-15226).

SIGNATURES

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

Dated: February 28, 2019


ENCANA CORPORATION (Registrant)

By:		/s/ Dawna I. Gibb
		Name: Dawna I. Gibb Title: Assistant Corporate Secretary

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (File No. 333-216395) and on Form S-8 (File Nos. 333-124218, 333-85598, 333-140856 and 333-188758) of Encana Corporation of our report dated February 28, 2019 relating to the financial statements of Newfield Exploration Company, which appears in this Current Report on Form 8-K.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

February 28, 2019

Exhibit 23.2

LOGO

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

As independent petroleum engineers, we hereby consent to the references to our firm and inclusion of information contained in our third party letter report dated February 22, 2019 on the proved reserves of Newfield Exploration Company (the “Letter Report”), in the context in which they appear, in this Current Report on Form 8-K of Encana Corporation, as well as in the notes to the consolidated financial statements of Newfield Exploration Company incorporated therein.

We have also consented to the incorporation by reference in the Registration Statements on Form S-3 (File No. 333-216395) and on Form S-8 (File Nos. 333-124218, 333-85598, 333-140856 and 333-188758) of Encana Corporation, in accordance with the requirements of the Securities Act of 1933, as amended, of the references to our name, inclusion of information contained in the Letter Report, as well as to the references to our Letter Report, which appears in this Current Report on Form 8-K of Encana Corporation, in the context in which they appear.

We further consent to the inclusion of our Letter Report as Exhibit 99.5 in this Current Report on Form 8-K of Encana Corporation.

/s/ Ryder Scott Company, L.P.

Ryder Scott Company, L.P.

TBPE Firm Registration No. F-1580

Denver, Colorado

February 28, 2019

Exhibit 23.3

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

DeGolyer and MacNaughton

5001 Spring Valley Road

Suite 800 East

Dallas, Texas 75244

February 28, 2019

Encana Corporation

4400, 500 Centre Street S.E.

Calgary, Alberta T2P 2S5

Canada

Ladies and Gentlemen:

We hereby consent to the inclusion of references to our firm and to the opinion as mentioned below regarding our independent evaluation of estimates provided by Newfield Exploration Mid-Continent Inc. (“Newfield”) of the net proved oil, condensate, natural gas liquids, and gas reserves, as of December 31, 2018, of certain selected properties that Newfield has represented it holds, contained in this Current Report on Form 8-K of Encana Corporation, as well as in the notes to the consolidated financial statements of Newfield Exploration Company incorporated by reference therein, to be filed with the United States Securities and Exchange Commission on or about February 28, 2019. The opinion is contained in our report of third party dated January 28, 2019, with respect to the reserves estimates as of December 31, 2018. Additionally, we hereby consent to the incorporation by reference of such references to our firm and to our opinion in the Registration Statements on Form S-3 (File No. 333-216395) and on Form S-8 (File Nos. 333-124218, 333-85598, 333-140856, and 333-188758) of Encana Corporation. We further consent to the inclusion of our report of third party dated January 28, 2019, as Exhibit 99.6 in the Current Report on Form 8-K of Encana Corporation.

Very truly yours,

/s/ DeGolyer and MacNaughton

DeGOLYER and MacNAUGHTON

Texas Registered Engineering Firm F-716

Exhibit 23.4

LOGO

Encana Corporation

4400, 500 Centre Street S.E.

Calgary, Alberta T2P 2S5

Canada

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

We hereby consent to the use and reference to our name and reports auditing a portion of Encana Corporation’s petroleum and natural gas reserves as of December 31, 2018 (the “Reports”), and the information derived from our Reports, as described or incorporated by reference in: (i) this Current Report on Form 8-K of Encana Corporation, (ii) Encana Corporation’s Registration Statement on Form S-3 (File Nos. 333-216395) and (iii) Encana Corporation’s Registration Statements on Form S-8 (File Nos. 333-124218, 333-85598, 333-140856 and 333-188758), filed with the United States Securities and Exchange Commission.

Yours truly,

McDANIEL & ASSOCIATES CONSULTANTS LTD.

/s/ B. R. Hamm

B. R. Hamm, P. Eng.

President & CEO

Calgary, Alberta

February 28, 2019

2200, Bow Valley Square 3, 255 - 5 Avenue SW, Calgary AB T2P 3G6 Tel: (403) 262-5506 Fax: (403) 233-2744 www.mcdan.com

Exhibit 23.5

LOGO

Encana Corporation

4400, 500 Centre Street S.E.

Calgary, Alberta T2P 2S5

Canada

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS


Sincerely,

NETHERLAND, SEWELL & ASSOCIATES, INC.

By:		/s/ C.H. (Scott) Rees III
		C.H. (Scott) Rees III, P.E.
		Chairman and Chief Executive Officer

Dallas, Texas

February 28, 2019

Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.

LOGO

Exhibit 99.1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholder of Newfield Exploration Company

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Newfield Exploration Company and its subsidiaries (the “Company”) as of December 31, 2018 and 2017, and the related consolidated statements of operations and comprehensive income, of stockholders’ equity and of cash flows for each of the three years in the period ended December 31, 2018, including the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018 in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits of these consolidated financial statements in accordance with the standards of the PCAOB and in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud.

Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

February 28, 2019

We have served as the Company’s auditor since 1993.

Exhibit 99.2

THE AUDITED CONSOLIDATED FINANCIAL STATEMENTS OF NEWFIELD EXPLORATION COMPANY

NEWFIELD EXPLORATION COMPANY

CONSOLIDATED BALANCE SHEET

(In millions, except share data)


	December 31,
	2018			2017
ASSETS
Current assets:
Cash and cash equivalents	$	292		$	326
Accounts receivable, net		374			292
Inventories		24			15
Derivative assets		12			15
Other current assets		61			98

Total current assets		763			746

Oil and gas properties, net — full cost method ($1,043 and $1,200 were excluded from amortization at December 31, 2018 and 2017, respectively)		4,774			3,931
Other property and equipment, net		172			168
Derivative assets		—			1
Investments		22			24
Restricted cash		50			40
Other assets		37			51

Total assets	$	5,818		$	4,961

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	57		$	46
Accrued liabilities		665			591
Advances from joint owners		83			80
Asset retirement obligations		2			3
Derivative liabilities		—			98

Total current liabilities		807			818

Other liabilities		66			69
Derivative liabilities		—			26
Long-term debt		2,436			2,434
Asset retirement obligations		132			130
Deferred taxes		100			76

Total long-term liabilities		2,734			2,735

Commitments and contingencies (Note 12)
Stockholders’ equity:
Preferred stock ($0.01 par value, 5,000,000 shares authorized; no shares issued)		—			—
Common stock ($0.01 par value, 300,000,000 shares authorized at December 31, 2018 and 2017; 203,206,347 and 201,363,345 shares issued at December 31, 2018 and 2017, respectively)		2			2
Additional paid-in capital		3,369			3,303
Treasury stock (at cost, 2,291,605 and 1,658,476 shares at December 31, 2018 and 2017, respectively)		(72	)		(59	)
Accumulated other comprehensive income (loss)		(4	)		—
Retained earnings (deficit)		(1,018	)		(1,838	)

Total stockholders’ equity		2,277			1,408

Total liabilities and stockholders’ equity	$	5,818		$	4,961

The accompanying notes to consolidated financial statements are an integral part of this statement.

NEWFIELD EXPLORATION COMPANY

CONSOLIDATED STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME

(In millions, except per share data)


	Year Ended December 31,
	2018			2017			2016
Oil, gas and NGL revenues	$	2,630		$	1,765		$	1,468
Other Revenues		13			2			4

Total revenues		2,643			1,767			1,472
Operating expenses:
Lease operating		269			215			244
Transportation and processing		348			300			272
Production and other taxes		125			64			42
Depreciation, depletion and amortization		628			467			572
General and administrative		231			200			213
Ceiling test and other impairments		—			—			1,028
Other		12			6			20

Total operating expenses		1,613			1,252			2,391

Income (loss) from operations		1,030			515			(919	)

Other income (expense):
Interest expense		(151	)		(150	)		(154	)
Capitalized interest		59			61			51
Commodity derivative income (expense)		(101	)		(47	)		(191	)
Other, net		4			7			5

Total other income (expense)		(189	)		(129	)		(289	)

Income (loss) before income taxes		841			386			(1,208	)

Income tax provision (benefit):
Current		—			(78	)		9
Deferred		24			37			13

Total income tax provision (benefit)		24			(41	)		22

Net income (loss)	$	817		$	427		$	(1,230	)

Earnings (loss) per share:
Basic	$	4.08		$	2.14		$	(6.36	)

Diluted	$	4.06		$	2.13		$	(6.36	)

Weighted-average number of shares outstanding for basic earnings (loss) per share		200			199			193

Weighted-average number of shares outstanding for diluted earnings (loss) per share		201			200			193

Comprehensive income (loss):
Net income (loss)	$	817		$	427		$	(1,230	)
Other comprehensive income (loss), net of tax		(4	)		2			—

Comprehensive income (loss)	$	813		$	429		$	(1,230	)

The accompanying notes to consolidated financial statements are an integral part of this statement.

NEWFIELD EXPLORATION COMPANY

CONSOLIDATED STATEMENT OF CASH FLOWS

(In millions)


	Year Ended December 31,
	2018			2017			2016
Cash flows from operating activities:
Net income (loss)	$	817		$	427		$	(1,230	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		628			467			572
Deferred tax provision (benefit)		24			37			13
Stock-based compensation		51			34			22
Unrealized (gain) loss on derivative contracts		(120	)		83			392
Ceiling test and other impairments		—			—			1,028
Other, net		10			14			13
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable		(83	)		(60	)		22
Increase (decrease) in accounts payable and accrued liabilities		105			27			(3	)
Other items, net		53			(62	)		9

Net cash provided by (used in) operating activities		1,485			967			838

Cash flows from investing activities:
Additions to oil and gas properties		(1,467	)		(1,156	)		(868	)
Acquisitions of oil and gas properties		(30	)		(110	)		(486	)
Proceeds from sales of oil and gas properties		37			96			405
Additions to other property and equipment		(25	)		(23	)		(17	)
Redemptions of investments		—			50			—
Purchases of investments		—			(25	)		(25	)

Net cash provided by (used in) investing activities		(1,485	)		(1,168	)		(991	)

Cash flows from financing activities:
Proceeds from borrowings under credit arrangements		—			—			536
Repayments of borrowings under credit arrangements		—			—			(575	)
Debt issue costs		(8	)		—			—
Proceeds from issuances of common stock, net		3			3			779
Purchases of treasury stock, net		(13	)		(15	)		(22	)
Other		(6	)		(1	)		(3	)

Net cash provided by (used in) financing activities		(24	)		(13	)		715

Net increase (decrease) in cash, cash equivalents and restricted cash		(24	)		(214	)		562
Cash, cash equivalents and restricted cash, beginning of period		366			580			18

Cash, cash equivalents and restricted cash, end of period	$	342		$	366		$	580

The accompanying notes to consolidated financial statements are an integral part of this statement.

NEWFIELD EXPLORATION COMPANY

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

(In millions)


	Common Stock				Treasury Stock						Additional Paid-in Capital		Retained Earnings (Deficit)			Accumulated Other Comprehensive Income (Loss)			Total Stockholders’ Equity
	Shares		Amount		Shares			Amount			Additional Paid-in Capital		Retained Earnings (Deficit)			Accumulated Other Comprehensive Income (Loss)			Total Stockholders’ Equity
Balance, December 31, 2015		164.1		2		(0.6	)		(22	)		2,436		(1,035	)		(2	)		1,379
Issuances of common stock		36.1		—								779								779
Stock-based compensation												32								32
Treasury stock, net						(0.6	)		(22	)		—								(22	)
Net income (loss)														(1,230	)					(1,230	)

Balance, December 31, 2016		200.2		2		(1.2	)		(44	)		3,247		(2,265	)		(2	)		938
Issuances of common stock		1.2		—								3								3
Stock-based compensation												53								53
Treasury stock, net						(0.5	)		(15	)		—								(15	)
Net income (loss)														427						427
Other comprehensive income (loss), net of tax																	2			2

Balance, December 31, 2017		201.4		2		(1.7	)		(59	)		3,303		(1,838	)		—			1,408
Issuances of common stock		1.8		—								3								3
Stock-based compensation												63								63
Treasury stock, net						(0.6	)		(13	)		—								(13	)
Net income (loss)														817						817
Cumulative effect of accounting change														3						3
Other comprehensive income (loss), net of tax																	(4	)		(4	)

Balance, December 31, 2018		203.2	$	2		(2.3	)	$	(72	)	$	3,369	$	(1,018	)	$	(4	)	$	2,277

The accompanying notes to consolidated financial statements are an integral part of this statement.

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Organization and Summary of Significant Accounting Policies

Organization and Principles of Consolidation

We are an independent energy company engaged in the exploration, development and production of crude oil, natural gas and natural gas liquids (NGLs). Our U.S. operations are onshore and focus primarily on large scale, liquids-rich resource plays in the Anadarko Basin of Oklahoma, the Williston Basin of North Dakota and the Uinta Basin of Utah. In addition, we have oil assets offshore China, and gas assets in the Arkoma Basin of Oklahoma.

On October 31, 2018, we entered into an Agreement and Plan of Merger (the Merger Agreement), with Encana Corporation, a Canadian corporation (Encana) and Neapolitan Merger Corp., a Delaware corporation and an indirect, wholly-owned subsidiary of Encana (Merger Sub), pursuant to which Merger Sub will merge with and into the Company (the Merger), with the Company surviving the Merger as a wholly-owned subsidiary of Encana. See Note 20, “ Encana Merger Agreement -Treatment of Newfield Equity Awards ,” for additional disclosures.

Our consolidated financial statements include the accounts of Newfield Exploration Company, a Delaware corporation, and its subsidiaries. We proportionately consolidate our interests in oil and natural gas exploration and production joint ventures and partnerships in accordance with industry practice. All significant intercompany balances and transactions have been eliminated. Unless otherwise specified or the context otherwise requires, all references in these notes to “Newfield,” “we,” “us,” “our” or the “Company” are to Newfield Exploration Company and its subsidiaries.

Risks and Uncertainties

As an independent oil and natural gas producer, our revenue, profitability and future rate of growth are substantially dependent on prevailing prices for oil, natural gas and NGLs. Historically, the energy markets have been very volatile, and there can be no assurance that commodity prices will not be subject to wide fluctuations in the future. A substantial or extended decline in commodity prices could have a material adverse effect on our financial position, results of operations, cash flows, access to capital and on the quantities of oil, natural gas and NGL reserves that we can economically produce. Other risks and uncertainties that could affect us in a volatile commodity price environment include, but are not limited to, counterparty credit risk for our receivables, responsibility for decommissioning liabilities for offshore interests we no longer own, inability to access credit markets, regulatory risks and our ability to meet financial ratios and covenants in our financing agreements.

Use of Estimates

The preparation of financial statements in accordance with U.S. GAAP requires our management to make estimates and assumptions that affect the reported amounts of assets and liabilities; disclosure of contingent assets and liabilities at the date of the financial statements; the reported amounts of revenues and expenses during the reporting period; and the quantities and values of proved oil, natural gas and NGL reserves used in calculating depletion and assessing impairment of our oil and gas properties. Actual results could differ significantly from these estimates. Our most significant estimates are associated with the quantities of proved oil, natural gas and NGL reserves, the timing and amount of transfers of our unevaluated properties into our amortizable full cost pool, the recoverability of our deferred tax assets and the fair value of our derivative contracts.

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Restructuring Costs

Restructuring costs include severance and related benefit costs, costs associated with abandoned office space, employee relocation costs and other associated costs. Employee severance and related benefit costs are recognized on a straight-line basis over the required service period, if any. Employee relocation costs are expensed as incurred. On the date a leased property ceases to be used, a liability for non-cancellable office-lease costs associated with restructuring is recognized and measured at fair value on our consolidated balance sheet. Fair value estimates include assumptions regarding estimated future sublease payments. These estimates could materially differ from actual results and may require revision to initial estimates of the liability. See Note 17, “Restructuring Costs,” for additional disclosures.

Revenue Recognition

We adopted the accounting guidance issued by the FASB regarding revenues from contracts with customers on January 1, 2018. The adoption of the new guidance did not materially impact our existing policies governing the timing and amount of revenue recognition or the classification of revenues and associated expenses on our Consolidated Statement of Operations and Comprehensive Income.

All of our oil, natural gas and NGLs are sold at market-based prices adjusted for location and quality differentials to a variety of purchasers. Our production is sold either at the lease or transported to markets further downstream. Prior to the adoption of ASC 606 we recorded revenue when we delivered our production to the customer and collectability was reasonably assured. We now record revenue when control of our production transfers to the customer and collectability is probable. Substantially all of our customers pay us within 30 days in accordance with industry standards for the sale of oil, natural gas and NGLs. For sales at the lease, control transfers immediately and we record revenue for the amount we expect to receive from the purchaser. For contracts in which control transfers to the customer downstream from the lease, expected revenues are presented on a gross basis with related expenses incurred prior to the transfer of control to the customer presented as transportation and processing expenses.

Foreign Currency

The functional currency for our China operations is the U.S. dollar. Gains and losses incurred on transactions in a currency other than the U.S. dollar are recorded under the caption “Other income (expense) — Other, net” on our consolidated statement of operations.

Cash and Cash Equivalents

Cash and cash equivalents include highly liquid investments with a maturity of three months or less when acquired and are stated at cost, which approximates fair value. We invest cash in excess of near-term capital and operating requirements in U.S. Treasury Notes, Eurodollar time deposits and money market funds, which are classified as cash and cash equivalents on our consolidated balance sheet.

Restricted Cash

Restricted cash consists of amounts held in escrow accounts to satisfy future plug and abandonment obligations for our China operations. These amounts are restricted as to their current use and will be released as we plug and abandon wells and facilities in China.

Investments

Investments consist of debt and equity securities, a majority of which are classified as “available-for-sale” and stated at fair value. As a result of adoption of Accounting Standards Update 2016-01, we reclassified $2.5 million out of accumulated other comprehensive income (AOCI) into opening retained earnings. At December 31, 2018, no portion of AOCI within our consolidated stockholders’ equity was related to investments. Accordingly, unrealized gains and losses and the related deferred income tax effects are included in earnings and reported in other income (expense) within our Consolidated Statement of

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Operations. As of December 31, 2017 and 2016, the portion of accumulated other comprehensive income within our consolidated statement of stockholders’ equity related to investments was $3 million and $1 million, respectively. Realized gains or losses are computed based on specific identification of the securities sold. We regularly assess our investments for impairment and consider any impairment to be other than temporary if we intend to sell the security, it is more likely than not that we will be required to sell the security, or we do not expect to recover our cost of the security.

Allowance for Doubtful Accounts

We routinely assess material trade and other receivables to determine their collectability. Many of our receivables are from joint interest owners of properties we operate. Thus, we may have the ability to withhold future revenue disbursements to recover any non-payment of related joint interest billings. Generally, our oil and gas receivables are collected within 45 to 60 days of production. We accrue a reserve on a receivable when, based on the judgment of management, it is probable that a receivable will not be collected.

Other Current Assets

Other current assets primarily consist of federal income tax refunds receivable, capital and lease operating expense prepayments and other prepaid items, including but not limited to, rent and insurance. For the years ended December 31, 2018 and 2017, federal income tax refunds receivable were $24 million and $53 million, respectively.

Inventories

Inventories primarily consist of tubular goods and well equipment held for use in our oil and natural gas operations and oil produced but not sold in our China operations. Inventories are carried at the lower of cost or net realizable value. Substantially all of the crude oil from our offshore operations in China is produced into floating storage facilities and sold periodically as barge quantities accumulate. The carrying value of oil inventory is the sum of related production costs and depletion expense. See Note 3, “Inventories,” for further discussion.

Oil and Gas Properties

We use the full cost method of accounting for our oil and gas activities. Under this method, all costs incurred in the acquisition, exploration and development of oil and gas properties, including salaries, benefits, interest and other internal costs directly attributable to these activities, are capitalized into country-based cost centers. Proceeds from the sale of oil and gas properties are applied to reduce the costs in the applicable cost center unless the reduction would significantly alter the relationship between capitalized costs and proved reserves, in which case a gain or loss is recognized.

Capitalized costs and estimated future development costs are amortized using a unit-of-production method based on proved reserves associated with the applicable cost center. For each cost center, the net capitalized costs of oil and gas properties are limited to the lower of the unamortized cost or the cost center ceiling. A particular cost center ceiling is equal to the sum of:

•

the present value (10% per annum discount rate) of estimated future net revenues from proved reserves using oil, natural gas and NGL reserve estimation requirements, which require use of the unweighted average first-day-of-the-month commodity prices for the prior 12 months (SEC pricing), adjusted for market differentials applicable to our reserves (including the effects of derivative contracts that are designated for hedge accounting, if any); plus

•

the costs of properties not included in the costs being amortized, if any; less

•

related income tax effects.

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

If net capitalized costs of oil and gas properties exceed the cost center ceiling, we are subject to a ceiling test impairment to the extent of such excess. If required, a ceiling test impairment reduces earnings and stockholders’ equity in the period of occurrence and, holding other factors constant, results in lower depreciation, depletion and amortization expense in future periods.

The risk that we will be required to impair the carrying value of our oil and gas properties increases when oil, natural gas and NGL prices decrease significantly for a prolonged period, or if we have substantial downward revisions in our estimated proved reserves.

Costs associated with unevaluated properties are excluded from our full cost pool until we have evaluated the properties or impairment is indicated. The costs associated with unevaluated leasehold acreage, related seismic data and capitalized interest and direct internal costs are initially excluded from our full cost pool. Leasehold costs are either transferred to our full cost pool with the costs of drilling a well on the lease or are assessed at least annually for possible impairment or reduction in value. Leasehold costs are transferred to our full cost pool to the extent a reduction in value has occurred, or a charge is made against earnings if the costs were incurred in a country for which a reserve base has not been established.

See Note 6, “Oil and Gas Properties,” for a detailed discussion regarding our oil and gas property and our asset acquisitions and sales transactions.

Other Property and Equipment

Furniture, fixtures and equipment are recorded at cost and depreciated using the straight-line method over their estimated useful lives, which range from 3 to 7 years. Gathering systems and equipment are recorded at cost and depreciated using the straight-line method over their estimated useful lives of 25 years.

Asset Retirement Obligations

If a reasonable estimate of the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon wells can be made, we record a liability (an asset retirement obligation or ARO) on our consolidated balance sheet and capitalize the present value of the asset retirement cost in oil and gas properties in the period in which the ARO is incurred. Settlements include payments made to satisfy the AROs, as well as transfer of the AROs to purchasers of our divested properties.

In general, the amount of the initial recorded ARO and the costs capitalized will equal the estimated future costs to satisfy the abandonment obligation assuming normal operation of the asset, using current prices that are escalated by an assumed inflation factor up to the estimated settlement date, which is then discounted back to the date that the abandonment obligation was incurred using the credit adjusted risk-free rate for our Company. After recording these amounts, the ARO is accreted to its future estimated value and the original capitalized costs are depreciated on a unit-of-production basis within the related full cost pool. Both the accretion and depreciation are included in depreciation, depletion and amortization expense on our consolidated statement of operations. See Note 10, “Asset Retirement Obligations,” for further discussion.

Contingencies

We are subject to legal proceedings, claims, liabilities and environmental matters that arise in the ordinary course of business. We accrue for losses when such losses are considered probable and the amounts can be reasonably estimated. See Note 12, “Commitments and Contingencies,” for a more detailed discussion regarding our contingencies.

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Environmental Matters

Environmental costs that relate to current operations are expensed as incurred. Remediation costs that relate to an existing condition caused by past operations are accrued when it is probable that those costs will be incurred and can be reasonably estimated based upon evaluations of currently available facts related to each site.

Income Taxes

We use the liability method of accounting for income taxes. Under this method, deferred tax assets and liabilities are determined by applying tax regulations existing at the end of a reporting period to the cumulative temporary differences between the tax bases of assets and liabilities and their reported amounts in our financial statements. We assess the available positive and negative evidence to estimate if sufficient taxable income will be generated to utilize deferred tax assets. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized. We also evaluate potential uncertain tax positions, and if necessary, establish accruals for such items. See Note 8, “Income Taxes,” for further discussion.

Stock-Based Compensation

We apply a fair value-based method of accounting for stock-based compensation, which requires recognition in the financial statements of the cost of services received in exchange for equity and liability awards. For equity awards, compensation expense is based on the fair value on the grant date and is recognized in our financial statements over the applicable service period. The fair value of our service based restricted stock and restricted stock units are based on the Company’s stock price on the date of grant. We utilize the Black-Scholes option-pricing model to measure the fair value of stock options and a Monte Carlo lattice-based model for our market-based restricted stock units. We also have cash-settled restricted stock units that are accounted for under the liability method, which requires us to recognize the fair value of each award based on the Company’s stock price at the end of each period. See Note 15, “Stock-Based Compensation,” for a full discussion of our stock-based compensation.

Concentration of Credit Risk

We operate a substantial portion of our oil and gas properties. As the operator of a property, we make full payment for costs associated with the property and seek reimbursement from the other joint interest owners in the property for their share of those costs. In addition, when warranted, we require prepayments from our joint interest owners for drilling and completion projects. Our joint interest owners consist primarily of independent oil and gas producers whose ability to reimburse us could be negatively impacted by adverse market conditions.

The purchasers of our oil, gas and NGL production consist primarily of independent marketers, major oil and gas companies, refiners and gas pipeline companies. We perform credit evaluations of the purchasers of our production and monitor their financial condition on an ongoing basis. Based on our evaluations and monitoring, we obtain cash escrows, letters of credit or parental guarantees from some purchasers.

All of our derivative transactions were carried out in the over-the-counter market and are not typically subject to margin-deposit requirements. We monitor the credit ratings of our derivative counterparties on an ongoing basis and have netting arrangements that provide for offsetting payables against receivables by counterparty. Although we have entered into derivative contracts with multiple counterparties to mitigate our exposure to any individual counterparty, if any of our counterparties were to default on its obligations to us under the derivative contracts or seek bankruptcy protection, it could have a material adverse effect on our ability to fund our planned activities and could result in a larger percentage of our future production being subject to commodity price volatility. In addition, in poor economic environments and tight financial markets, the risk of a counterparty default is heightened and fewer counterparties may participate in derivative transactions, which could result in greater concentration of our exposure to any one counterparty or a larger percentage of our future production being subject to commodity price changes. The use of derivative transactions involves the risk that the counterparties, which generally are

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

financial institutions, will be unable to meet the financial terms of such transactions. Our derivative contracts are with multiple counterparties to minimize our exposure to any individual counterparty, and we have netting arrangements with all of our counterparties that provide for offsetting payables against receivables by counterparty.

At December 31, 2018, 8 of our 11 counterparties accounted for approximately 88% of our contracted volumes, with the largest counterparty accounting for approximately 16%. At December 31, 2018, approximately 92% of our contracted volumes subject to derivative instruments were with lenders under our credit facility. Our credit facility, senior notes and substantially all of our derivative instruments contain provisions that provide for cross defaults and acceleration of those debt and derivative instruments in certain situations.

Major Customers

During 2018, Valero Energy Corporation accounted for 13% of our total revenues. In 2017, none of our customers accounted for 10% or more of our total revenues. During 2016, China National Offshore Oil Corporation Ltd. accounted for 12% of our total revenues. We believe that the loss of a major customer would not have a material adverse effect on us because alternative purchasers are available.

Derivative Financial Instruments

Our derivative instruments are recorded on the consolidated balance sheet at fair value as either an asset or a liability with changes in fair value recognized currently in earnings. While we utilize our derivative instruments to manage the price risk attributable to our expected oil, gas and NGL production, we have elected not to designate our derivative instruments as accounting hedges under the accounting guidance.

The related cash flow impact of our derivative activities is reflected as cash flows from operating activities unless the derivatives are determined to have a significant financing element at inception, in which case they are classified within financing activities. See Note 4, “Derivative Financial Instruments,” for a more detailed discussion of our derivative activities.

Offsetting Assets and Liabilities

Our derivative financial instruments are subject to master netting arrangements and are reflected on our consolidated balance sheet accordingly. See Note 4, “Derivative Financial Instruments,” for details regarding the gross amounts, as well as the impact of our netting arrangements on our net derivative position.

New Accounting Requirements

In May 2014, the Financial Accounting Standards Board (FASB) issued guidance regarding the accounting for revenue from contracts with customers. The guidance is effective for interim and annual periods beginning after December 15, 2017 and may be applied retrospectively or using a modified retrospective approach to adjust retained earnings (deficit). We adopted the guidance in the first quarter of 2018. Prior period amounts have not been adjusted and continue to be reflected in accordance with the Company’s historical accounting. The adoption of this guidance did not have a material impact on the Company’s Consolidated Financial Statements.

In November 2016, the FASB issued guidance regarding the classification and presentation of changes in restricted cash in the statement of cash flows. The guidance requires amounts described as restricted cash be included with cash and cash equivalents when reconciling the beginning of period and end of period total amounts shown on the statement of cash flows. We adopted this guidance in the first quarter of 2018 utilizing a full retrospective approach.

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table summarizes the impact of the adoption of the new accounting standard to the Company’s Consolidated Statements of Cash Flows for the twelve months ended December 31, 2017 and December 31, 2016.


	Twelve months ended December 31,
	2017								2016
	As Originally Presented			Adoption Adjustments		As Adjusted			As Originally Presented		Adoption Adjustments		As Adjusted
	(In millions)								(In millions)
Net cash provided by (used in) operating activities	$	952		$	15	$	967		$	826	$	12	$	838
Net increase (decrease) in cash, cash equivalents and restricted cash		(229	)		15		(214	)		550		12		562
Cash, cash equivalents and restricted cash, beginning of period		555			25		580			5		13		18

Cash, cash equivalents and restricted cash, end of period	$	326		$	40	$	366		$	555	$	25	$	580

In January 2016, the FASB issued guidance regarding several broad topics related to the recognition and measurement of financial assets and liabilities. The guidance is effective for interim and annual periods beginning after December 15, 2017. We adopted this guidance in 2018 using a modified approach, as permitted, with a $2.5 million opening adjustment from accumulated other comprehensive income to retained earnings. There was not a material impact to current period earnings.

In February 2016, the FASB issued guidance regarding the accounting for leases. The guidance requires recognition of certain leases on the balance sheet. The guidance is effective for interim and annual periods beginning after December 15, 2018. Under the transition method selected by the Company, leases existing at, or entered into after, January 1, 2019 will be required to be recognized and measured. Prior period amounts will not be adjusted, but will continue to be reflected in accordance with historical accounting. The adoption of this standard is estimated to result in the recording of operating lease assets and operating lease liabilities of approximately $61 million as of December 31, 2018, with no related impact on the Company’s Consolidated Statement of Stockholders’ Equity or Consolidated Statement of Operations and Comprehensive Income. Short-term leases will not be recorded on the balance sheet.

In February 2018, the FASB issued guidance regarding the reclassification of certain tax effects from accumulated other comprehensive income. The guidance allows a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Cuts and Jobs Act of 2017. The guidance is effective for interim and annual periods beginning after December 15, 2018, with early adoption permitted. We adopted this guidance in the first quarter of 2018, as permitted, with an immaterial opening adjustment from accumulated other comprehensive income to retained earnings.

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

2. Accounts Receivable

Accounts receivable consisted of the following at December 31:


	2018			2017
	(In millions)
Revenue	$	216		$	175
Joint interest		137			108
Other		36			25
Reserve for doubtful accounts		(15	)		(16	)

Total accounts receivable, net	$	374		$	292

Reserve for doubtful accounts at December 31, 2018 and 2017 includes an allowance for $15 million related to the sale of our Malaysia operations in 2014. Arbitration with the buyers of our Malaysian operations is scheduled to occur in the first half of 2019, see Note 12, “Commitments and Contingencies” for additional details regarding our Malaysia litigation.

3. Inventories

Inventories primarily consist of tubular goods and well equipment held for use in our oil and natural gas operations, and oil produced but not sold. Inventories are carried at the lower of cost or net realizable value. At December 31, 2018, crude oil inventory totaled approximately $5 million. We had no crude oil inventory at December 31, 2017.

4. Derivative Financial Instruments

Commodity Derivative Instruments

We utilize derivative strategies that consist of either a single derivative instrument or a combination of instruments to manage the variability in cash flows associated with the forecasted sale of our future domestic oil, natural gas, and NGL production. While the use of derivative instruments may limit or partially reduce the downside risk of adverse commodity price movements, their use also may limit future income from favorable commodity price movements.

•

Fixed-price swaps. With respect to a swap position, the counterparty is required to make a payment to us if the settlement price for any settlement period is less than the swap strike price, and we are required to make a payment to the counterparty if the settlement price for any settlement period is greater than the swap strike price.

•

Collars (combination of purchased put options (floor) and sold call options (ceiling)) . For a collar position, the counterparty is required to make a payment to us if the settlement price for any settlement period is below the floor strike price while we are required to make payment to the counterparty if the settlement price for any settlement period is above the ceiling strike price. Neither party is required to make a payment to the other party if the settlement price for any settlement period is equal to or greater than the floor strike price and equal to or less than the ceiling strike price.

While we do not use derivatives for speculative trading purposes, periodically, we may restructure our derivative positions by purchasing, selling or unwinding certain derivative instruments. For discussion of the accounting policies associated with our derivative financial instruments (including the offsetting of derivative assets and liabilities), see Note 1, “Organization and Summary of Significant Accounting Policies.”

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Our oil and gas derivative contracts are settled based upon reported prices on the NYMEX, and our NGLs are settled on posted prices at Mont Belvieu. The estimated fair value of these contracts is based upon various factors, including future prices, over-the-counter quotations, estimated volatility, non-performance risk adjustments using counterparty rates of default and time to maturity. The calculation of the fair value of options requires the use of an option-pricing model. See Note 5, “Fair Value Measurements.”

During the fourth quarter of 2018, we paid approximately $18 million to terminate all 2019 oil positions. At December 31, 2018, our only outstanding derivative positions were gas fixed-price swaps and gas collars as set forth below.

Natural Gas


Period and Type of Instrument			NYMEX Contract Price Per MMBtu
							Collars
	Volume in MMMBtus		Swaps (Weighted Average)		Puts (Weighted Average)		Floors (Weighted Average)		Ceilings (Weighted Average)		Estimated Fair Value Asset (Liability)
											(In millions)
2019:
Fixed-price swaps		13,550	$	3.89	$	—	$	—	$	—	$	11
Collars		9,000		—		—		3.00		3.47		1
Total											$	12

Additional Disclosures about Derivative Financial Instruments

We had derivative financial instruments recorded in our consolidated balance sheet as assets (liabilities) at their respective estimated fair value, as set forth below.


	Derivative Assets									Derivative Liabilities
	Gross Fair Value		Offset in Balance Sheet			Balance Sheet Location				Gross Fair Value			Offset in Balance Sheet		Balance Sheet Location
	Gross Fair Value		Offset in Balance Sheet			Current		Noncurrent		Gross Fair Value			Offset in Balance Sheet		Current			Noncurrent
December 31, 2018	(In millions)									(In millions)
Natural gas positions		13		(1	)		12		—		(1	)		1		—			—

Total	$	13	$	(1	)	$	12	$	—	$	(1	)	$	1	$	—		$	—

December 31, 2017
Oil positions	$	48	$	(48	)	$	—	$	—	$	(170	)	$	48	$	(96	)	$	(26	)
Natural gas positions		22	$	(6	)		15		1		(6	)		6		—			—
NGL positions		—	$	—			—		—		(2	)		—		(2	)		—

Total	$	70	$	(54	)	$	15	$	1	$	(178	)	$	54	$	(98	)	$	(26	)

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The amount of gain (loss) recognized in “Commodity derivative income (expense)” in our consolidated statement of operations and comprehensive income related to our derivative financial instruments follows:


	Year Ended December 31,
	2018			2017			2016
	(In millions)
Derivatives not designated as hedging instruments:
Realized gain (loss) on oil positions	$	(218	)	$	48		$	199
Realized gain (loss) on natural gas positions		(1	)		(12	)		2
Realized gain (loss) on NGL positions		(2	)		—			—

Total realized gain (loss)		(221	)		36			201

Unrealized gain (loss) on oil positions		122			(152	)		(316	)
Unrealized gain (loss) on natural gas positions		(4	)		71			(76	)
Unrealized gain (loss) on NGL positions		2			(2	)		—

Total unrealized gain (loss)		120			(83	)		(392	)

Total	$	(101	)	$	(47	)	$	(191	)

5. Fair Value Measurements

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The authoritative guidance requires disclosure of the framework for measuring fair value and requires that fair value measurements be classified and disclosed in one of the following categories:


Level 1:		Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. We consider active markets as those in which transactions for the assets or liabilities occur with sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2:		Quoted prices in markets that are not active, or inputs that are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that we value using observable market data. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange traded derivatives such as over-the-counter commodity fixed-price swaps and, as of the third quarter of 2017, commodity options (i.e. price collars, sold puts, purchased calls or swaptions). We use a modified Black-Scholes option pricing valuation model for option and swaption derivative contracts that considers various inputs including: (a) forward prices for commodities, (b) time value, (c) volatility factors, (d) counterparty credit risk and (e) current market and contractual prices for the underlying instruments.

Level 3:		Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e., supported by little or no market activity).

Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy. We continue to evaluate our inputs to ensure the fair value level classification is appropriate. When transfers between levels occur, it is our policy to assume that the transfer occurred at the date of the event or change in circumstances that caused the transfer.

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —(Continued)

The determination of the fair values of our derivative contracts incorporates various factors, which include not only the impact of our non-performance risk on our liabilities but also the credit standing of the counterparties involved. We utilize counterparty rate of default values to assess the impact of non-performance risk when evaluating receivables from counterparties and our credit rate when evaluating liabilities.

Recurring Fair Value Measurements

The following table summarizes the valuation of our assets and liabilities that are measured at fair value on a recurring basis.


	Fair Value Measurement Classification
	Quoted Prices in Active Markets for Identical Assets or (Liabilities) (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Total
	(In millions)
As of December 31, 2018:
Money market fund investments	$	207		$	—		$	—	$	207
Deferred compensation plan assets		7			—			—		7
Equity securities available-for-sale		12			—			—		12
Oil, gas and NGL derivative contracts		—			12			—		12
Stock-based compensation liability awards		(3	)		—			—		(3	)

Total	$	223		$	12		$	—	$	235

As of December 31, 2017:
Money market fund investments	$	162		$	—		$	—	$	162
Deferred compensation plan assets		7			—			—		7
Equity securities available-for-sale		12			—			—		12
Oil, gas and NGL derivative contracts		—			(108	)		—		(108	)
Stock-based compensation liability awards		(7	)		—			—		(7	)

Total	$	174		$	(108	)	$	—	$	66

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Level 3 Fair Value Measurements

The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 financial instruments in the fair value hierarchy for the indicated periods. There were no Level 3 in 2018.


	Derivatives			Total
	(In millions)
Balance at January 1, 2016	$	(308	)	$	(308	)
Unrealized gains (losses) included in earnings		(33	)		(33	)
Purchases, issuances, sales and settlements:
Settlements		220			220
Transfers into Level 3		—			—
Transfers out of Level 3 ⁽¹⁾		46			46

Balance at December 31, 2016	$	(75	)	$	(75	)

Change in unrealized gains or losses included in earnings relating to Level 3 instruments still held at December 31, 2016	$	13		$	13

Balance at January 1, 2017	$	(75	)	$	(75	)
Unrealized gains (losses) included in earnings		(17	)		(17	)
Purchases, issuances, sales and settlements:
Settlements		30			30
Transfers into Level 3		—			—
Transfers out of Level 3 ⁽²⁾		62			62

Balance at December 31, 2017	$	—		$	—

Change in unrealized gains or losses included in earnings relating to Level 3 instruments still held at December 31, 2017	$	—		$	—

(1)	During the second quarter of 2016, we transferred $46 million of derivative option contracts out of the Level 3 category as a result of our Level 3 swaptions being exercised by the counterparties as swaps in June 2016.

(2)

During the third quarter of 2017, we transferred $62 million of derivative option contracts out of the Level 3 hierarchy into Level 2 hierarchy as a result of our ability to derive volatility inputs from directly observable sources. Therefore, we have no financial assets nor liabilities classified as Level 3 at December 31, 2018.

Fair Value of Debt

The estimated fair value of our notes, based on quoted prices in active markets (Level 1) as of December 31, was as follows:


	2018		2017
	(In millions)
5 ³ ⁄ ₄ % Senior Notes due 2022	$	757	$	802
5 ⁵ ⁄ ₈ % Senior Notes due 2024		1,008		1,089
5 ³ ⁄ ₈ % Senior Notes due 2026		695		739

Any amounts outstanding under our revolving credit facility and money market lines of credit as of the indicated dates are stated at cost, which approximates fair value. See Note 11, “Debt.”

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

6. Oil and Gas Properties

At December 31, oil and gas properties consisted of the following:


	2018			2017
	(In millions)
Proved	$	24,877		$	23,272
Unproved		1,043			1,200

Gross oil and gas properties		25,920			24,472
Accumulated depreciation, depletion and amortization		(10,637	)		(10,032	)
Accumulated impairment		(10,509	)		(10,509	)

Net oil and gas properties	$	4,774		$	3,931

We capitalized approximately $115 million, $124 million and $121 million of interest and direct internal costs in 2018, 2017 and 2016, respectively.

Costs withheld from amortization as of December 31, 2018 consisted of the following:


	Costs Incurred In
	2018		2017		2016		2015		Total
	(In millions)
Acquisition costs	$	40	$	107	$	483	$	93	$	723
Exploration costs		—		—		—		—		—
Capitalized internal cost		23		38		49		30		140
Capitalized interest		59		61		51		9		180

Total costs withheld from amortization	$	122	$	206	$	583	$	132	$	1,043

Ceiling Test Impairments

Under the full cost method, we are subject to quarterly calculations of a “ceiling” or limitation on the amount of oil and gas property costs that can be capitalized on our balance sheet. At December 31, 2018, the ceiling value of our reserves was calculated based upon SEC pricing of $65.57 per barrel for oil and $3.10 per MMBtu for natural gas. Using these prices, our ceiling values exceeded the net capitalized costs of oil and gas properties for the U.S. and China, respectively, and no ceiling test impairment was required in 2018. At December 31, 2017, the ceiling value of our reserves was calculated based upon SEC pricing of $51.34 per barrel for oil and $2.98 per MMBtu for natural gas. Using these prices, our ceiling values exceeded the net capitalized costs of oil and gas properties for the U.S. and China, respectively, and no ceiling test impairment was required in 2017. Ceiling test impairments during 2016 consisted of the following:


	SEC Pricing				US Ceiling Test Impairments				China Ceiling Test Impairments				Total Ceiling Test Impairments
	Oil		Natural Gas		Gross		Net of Tax ⁽¹⁾		Gross		Net of Tax ⁽¹⁾		Gross		Net of Tax ⁽¹⁾
	(Per Bbl)		(Per MMBtu)		(In millions)
2016 Quarter Ended:
March 31	$	46.23	$	2.40	$	461	$	461	$	45	$	45	$	506	$	506
June 30		43.14		2.24		501		501		21		21		522		522
September 30		41.73		2.28		—		—		—		—		—		—
December 31		42.82		2.48		—		—		—		—		—		—

Total 2016					$	962	$	962	$	66	$	66	$	1,028	$	1,028

(1)	There was no tax impact due to a full valuation allowance on our deferred tax assets. See Note 8, “Income Taxes,” for additional information regarding the deferred tax asset valuation allowance.

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Future declines in SEC pricing or downward revisions to our estimated proved reserves could result in additional ceiling test impairments of our oil and gas properties in subsequent periods.

Bohai Bay (China) Sales Agreement

In May 2017, we closed our previously disclosed sale transaction with certain of our joint venture partners to divest our interest in the Bohai Bay field in China for approximately $32 million, including customary post-close adjustments. Upon completion of our assessment, the sale of our Bohai Bay assets did not significantly alter the relationship between capitalized costs and proved reserves for our China full cost pool and, as such, all proceeds were recorded as adjustments to our China full cost pool with no gain or loss recognized. These consolidated financial statements include the results of our Bohai Bay operations through the date of sale.

Texas Asset Sale

In September 2016, we closed the sale of substantially all of our oil and gas assets in Texas for approximately $380 million, subject to customary post-close adjustments. The sale of our Texas assets did not significantly alter the relationship between capitalized costs and proved reserves for our U.S. cost pool, and as such, all proceeds were recorded as adjustments to our domestic full cost pool with no gain or loss recognized. These consolidated financial statements include the results of our Texas operations through the date of sale.

Anadarko Basin Acquisition

In June 2016, we acquired additional properties in the Anadarko Basin STACK play for an adjusted cash purchase price of $476 million, subject to customary post-close adjustments. We also assumed asset retirement obligations of $8 million. We allocated $398 million to unproved properties and wells in progress and $86 million to proved oil and gas properties.

Other Asset Acquisitions and Sales

During 2018, 2017 and 2016, we acquired various other oil and gas properties for approximately $30 million, $100 million and $7 million, respectively, and sold certain other oil and gas properties for proceeds of approximately $37 million, $72 million and $39 million, respectively. The related cash flows and results of operations for these divested assets are included in our consolidated financial statements up to the date of sale. All of the proceeds associated with our asset sales were recorded as adjustments to our domestic full cost pool.

7. Other Property and Equipment

At December 31, other property and equipment consisted of the following:


	2018			2017
	(In millions)
Furniture, fixtures and equipment	$	174		$	165
Gathering systems and equipment		120			115
Accumulated depreciation and amortization		(122	)		(112	)

Net other property and equipment	$	172		$	168

During 2018, we sold $11 million of furniture, fixtures and equipment and removed the associated asset and accumulated depreciation accordingly.

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

8. Income Taxes

For the years ended December 31, income (loss) before income taxes consisted of the following:


	2018		2017		2016
	(In millions)
U.S.	$	790	$	357	$	(1,181	)
International		51		29		(27	)

Total income (loss) before income taxes	$	841	$	386	$	(1,208	)

For the years ended December 31, the total provision (benefit) for income taxes consisted of the following:


	2018			2017			2016
	(In millions)
Current taxes:
U.S. federal	$	(3	)	$	(79	)	$	(13	)
U.S. state		—			—			—
International		3			1			22

		—			(78	)		9

Deferred taxes:
U.S. federal		(11	)		4			10
U.S. state		24			37			13
International		11			(4	)		(10	)

	$	24		$	37		$	13

Total provision (benefit) for income taxes	$	24		$	(41	)	$	22

The provision for income taxes on the consolidated statement of operations for the year ended December 31, 2018 of $24 million was attributable to the provision for Oklahoma state deferred tax expense of $40 million, and the tax benefit for the 2017 Oklahoma provision to return adjustment of $16 million recorded in the third quarter ended September 30, 2018. Other taxing jurisdictions were in a net deferred tax asset position for which a corresponding valuation allowance was recorded resulting in zero deferred tax provision for those jurisdictions.

The following table presents a reconciliation of the United States statutory income tax rate to our effective income tax rate:


	2018			2017			2016
U.S. statutory income tax rate		21.0	%		35.0	%		35.0	%
State and local income taxes, net of federal effect		4.6			6.9			—
Valuation allowance, domestic		(23.1	)		(210.1	)		(35.5	)
Valuation allowance, international		(1.0	)		(1.2	)		(2.4	)
Foreign tax on foreign earnings		1.5			1.5			0.6
Impact of Tax Act		—			157.4			—
Provision to return, Oklahoma		(1.9	)		—			—
Nondeductible compensation		1.7			—			—
Other		0.1			—			0.5

Effective income tax rate		2.9	%		(10.5	)%		(1.8	)%

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Our effective tax rate for 2018 differs from the U.S. statutory rate primarily due to domestic and international deferred tax asset valuation allowances and state income taxes as discussed below.

At December 31, the components of our deferred tax asset (liability) were as follows:


	2018			2017 ⁽¹⁾			2016
Deferred tax asset:
Net operating loss carryforwards	$	367		$	314		$	301
Alternative Minimum Tax credit		—			—			73
Stock-based compensation		7			11			15
Oil and gas properties		44			15			306
Commodity derivatives		—			19			9
Foreign tax credit		—			—			593
Other		6			3			13

Total deferred tax asset		424			362			1,310
Deferred tax asset valuation allowances		(159	)		(362	)		(1,310	)

Net deferred tax asset		265			—			—

Deferred tax liability:
Commodity derivatives		(3	)		—			—
Oil and gas properties		(362	)		(76	)		(39	)

Total deferred tax liability		(365	)		(76	)		(39	)

Net deferred tax liability	$	(100	)	$	(76	)	$	(39	)

(1)	The December 31, 2017 deferred tax asset (liability) has been adjusted for the lower federal statutory rate under the Tax Act.

At December 31, 2018 we have a net deferred tax liability in Oklahoma of $99 million. Most other taxing jurisdictions are in a net deferred tax asset position, for which we recorded an offsetting full valuation allowance, as prescribed by the accounting standards.

As of December 31, 2018 and 2017, we had gross net operating loss (NOL) carryforwards of approximately $1.75 billion for federal income tax, and $2.0 billion and $1.5 billion, respectively, for state income tax purposes, which may be used in future years to offset taxable income. To the extent not utilized, the federal NOL carryforwards will begin to expire during the years 2020 through 2037.

Utilization of deferred tax assets is dependent upon generating sufficient future taxable income in the appropriate jurisdictions within the carryforward period. Estimates of future taxable income can be significantly affected by changes in oil, gas and NGL prices; estimates of the timing and amount of future production; and estimates of future operating and capital costs. Therefore, no certainty exists that we will be able to fully utilize our existing deferred tax assets.

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The change in our deferred tax asset valuation allowance is as follows at December 31:


	2018			2017			2016
	(In millions)
Balance at the beginning of the year	$	(362	)	$	(1,310	)	$	(790	)
Charged to provision for income taxes:
U.S. state net operating loss carryforwards		—			7			(4	)
U.S. federal and state valuation allowance		195			343			(466	)
Foreign tax credit valuation allowance		—			593			(21	)
China valuation allowance		8			5			(29	)

Balance at the end of the year	$	(159	)	$	(362	)	$	(1,310	)

Due to the ceiling test impairments of our oil and gas properties in prior periods, we moved from a deferred tax liability position to a deferred tax asset position in most taxing jurisdictions. We consider it more likely than not that the related tax benefits will not be realized and therefore, we recorded a full valuation allowance on our deferred tax assets of $159 million and $362 million for the years ended December 31, 2018 and 2017, respectively. The net change in the U.S. federal and state valuation allowance for 2018 and 2017 was $195 million and $343 million, respectively, and for 2017 included a decrease of $199 million for the corporate tax rate reduction under the Tax Act. The net change in the U.S. federal and state valuation allowance for 2016 of $466 million included an increase of $37 million for the early adoption of the simplification of employee share-based payment transactions. The net change in the foreign tax credit valuation allowance for 2017 of $593 million included a decrease of $185 million for the conversion of the credit to a net operating loss and a decrease of $408 million for the permanent loss of the foreign tax credit under the Tax Act. We recorded a full valuation allowance on our China deferred tax assets of $29 million and $37 million for the years ended December 31, 2018 and 2017, respectively.

Given the rebound in oil prices during 2018, we believe the reversal of the remaining allowance may be warranted in future periods. A release of the valuation allowance would result in the recognition of certain deferred tax assets and a decrease to income tax expense in the period the release is recorded. The exact timing and amount of the valuation allowance release are subject to change on the basis of our forecasted pre-tax earnings which we continue to asses based on available information each reporting period.

As of December 31, 2018, we did not have a liability for uncertain tax positions, and as such, we did not accrue related interest or penalties. The tax years 2015 through 2017 remain open to examination for federal income tax purposes and by the other major taxing jurisdictions to which we are subject.

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

9. Accrued Liabilities

Accrued liabilities consisted of the following at December 31:


	2018		2017
	(In millions)
Revenue payable	$	320	$	239
Accrued capital costs		161		173
Accrued lease operating expenses		39		22
Employee incentive expense		33		44
Accrued interest on debt		65		67
Taxes payable		24		11
Other		23		35

Total accrued liabilities	$	665	$	591

10. Asset Retirement Obligations

The change in our ARO for each of the three years ended December 31, is set forth below:


	2018			2017			2016
	(In millions)
Balance at January 1	$	133		$	156		$	194
Accretion expense		8			9			10
Additions ⁽¹⁾		3			3			15
Revisions ⁽²⁾		(8	)		(25	)		(23	)
Settlements ⁽³⁾		(2	)		(10	)		(40	)

Balance at December 31		134			133			156
Less: Current portion of ARO at December 31		(2	)		(3	)		(2	)

Total long-term ARO at December 31	$	132		$	130		$	154

(1)	For the year ended December 31, 2016, additions include $8 million of abandonment obligations assumed through our Anadarko Basin acquisition.

(2)	Revisions are primarily due to changes in cost estimates and timing of expected abandonment.

(3)	For the year ended December 31, 2017, settlements include $7 million related to the sale of our interest in the Bohai Bay field in China. For the year ended December 31, 2016, settlements include $35 million related to the sale of our Texas assets. See Note 6, “Oil and Gas Properties.”

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

11. Debt

At December 31, our debt consisted of the following:


	2018			2017
	(In millions)
Senior unsecured debt:
5 ³ ⁄ ₄ % Senior Notes due 2022	$	750		$	750
5 ⁵ ⁄ ₈ % Senior Notes due 2024		1,000			1,000
5 ³ ⁄ ₈ % Senior Notes due 2026		700			700

Total senior unsecured debt		2,450			2,450
Debt issuance costs		(14	)		(16	)

Total long-term debt	$	2,436		$	2,434

Credit Arrangements

As of December 31, 2018, we had no borrowings under our money market lines of credit or revolving credit facility and had no letters of credit outstanding. On March 23, 2018, we amended our Credit Agreement. This amendment extended the maturity date of the revolving credit facility from June 25, 2020 to May 1, 2023 and increased the borrowing capacity from $1.8 billion to $2.0 billion. The amendment also added an accordion feature providing the option to further increase the borrowing capacity by up to an additional $750 million. We incurred $8 million of deferred financing costs related to this amendment, which will be amortized over the term of the agreement. As of December 31, 2018, the largest individual loan commitment by any lender was 9% of total commitments.

Subject to compliance with restrictive covenants in our credit facility, our available borrowing capacity (before any amounts drawn) under our money market lines of credit with various institutions, the availability of which is at the discretion of those financial institutions, was $125 million at December 31, 2018.

Loans under the credit facility bear interest, at our option, equal to (a) the Alternate Base Rate (as defined in the Credit Agreement), plus a margin that is based on a grid of our debt rating (100 basis points per annum at December 31, 2018) or (b) the Adjusted Eurodollar Rate (as defined in the Credit Agreement), plus a margin that is based on a grid of our debt rating (200 basis points per annum at December 31, 2018).

Under our credit facility, we pay commitment fees on available but undrawn amounts based on a grid of our debt rating (37.5 basis points per annum at December 31, 2018). We incurred aggregate annual commitment fees under our credit facility of approximately $7 million for each of the years ended December 31, 2018, 2017 and 2016, respectively, which were recorded in “Interest expense” on our consolidated statement of operations and comprehensive income. We incurred approximately $3 million of financing costs related to amending our revolving credit facility in March 2016, which were also included in “Interest expense” on our consolidated statement of operations and comprehensive income.

Our credit facility has restrictive financial covenants that include the maintenance of a ratio of total debt to book capitalization not to exceed 0.6 to 1.0 and the maintenance of a ratio of earnings before gain or loss on the disposition of assets, interest expense, income taxes and certain non-cash items (such as depreciation, depletion and amortization expense, unrealized gains and losses on commodity derivatives and ceiling test impairments) to interest expense of at least 2.5 to 1.0. At December 31, 2018, we were in compliance with all of our debt covenants.

Letters of credit are subject to a fee of 20 basis points and annual fees based on a grid of our debt rating (200 basis points at December 31, 2018).

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The credit facility includes events of default relating to customary matters, including, among other things, nonpayment of principal, interest or other amounts; violation of covenants; inaccuracy of representations and warranties in any material respect when made; a change of control; or certain other material adverse changes in our business. Our senior notes also contain standard events of default. If any of the foregoing defaults were to occur, our lenders under the credit facility could terminate future lending commitments, and our lenders under both the credit facility and our notes could declare the outstanding borrowings due and payable. In addition, our credit facility, senior notes and substantially all of our derivative arrangements contain provisions that provide for cross defaults and acceleration of those debt and derivative instruments in certain situations.

Senior Subordinated Notes

Interest on our senior notes is payable semi-annually. The notes are unsecured and unsubordinated obligations and rank equally with all of our other existing and future unsecured and unsubordinated obligations. We may redeem some or all of our senior notes at any time before their maturity at a redemption price based on a make-whole amount plus accrued and unpaid interest to the date of redemption. The indentures governing our senior notes contain covenants that may limit our ability to, among other things, incur debt secured by liens; enter into sale/leaseback transactions; and enter into merger or consolidation transactions. The indentures also provide that if any of our subsidiaries guarantee any of our indebtedness at any time in the future, then we will cause our senior notes to be equally and ratably guaranteed by that subsidiary.

12. Commitments and Contingencies

We have various commitments for firm transportation, operating lease agreements for office space and other agreements. As of December 31, 2018, future minimum payments under these non-cancelable agreements are as follows:


	Firm Transportation		Office Space		Drilling- Related		Other		Total
	(In millions)
Year Ending December 31,
2019	$	79	$	23	$	38	$	31	$	171
2020		36		22		—		12		70
2021		23		22		—		5		50
2022		22		15		—		4		41
2023		20		1		—		3		24
Thereafter		90		—		—		15		105

Total minimum future payments	$	270	$	83	$	38	$	70	$	461

Firm transportation is comprised of various agreements with third parties for oil and gas gathering and transportation. Rent expense with respect to our lease commitments for office space for the years ended December 31, 2018, 2017 and 2016 was $16 million, $16 million and $21 million, respectively. Our other agreements are primarily other equipment leases. Payments under our drilling-related contracts are accounted for as capital additions to our oil and gas properties and will be less than the gross obligation disclosed in wells in which we do not own a 100% working interest.

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Not included in the table above are crude oil minimum volume delivery commitments that relate to our Uinta Basin production with two Salt Lake City, Utah refiners. One delivery commitment is for approximately 15,000 barrels of oil per day through May 2020. The second commitment is for 16,000 barrels of oil per day through August 2025. As of December 31, 2018, our delivery commitments through 2025 were as follows:


	Oil
Year Ending December 31,	(MBbls)
2019		11,315
2020		8,136
2021		5,840
2022		5,840
2023		5,840
Thereafter		9,744

Total delivery commitments		46,715

Given the volatility in oil and natural gas prices and the related impact on our 2019 planned capital investments, as well as the potential impact on development plans in future years, we could fail to deliver the minimum production required under these commitments. In the event that we are unable to meet our crude oil volume delivery commitments, we would incur deficiency fees ranging from $3.50 to $6.50 per barrel. During 2018, 2017 and 2016, we incurred $10 million, $29 million, and $16 million, of Uinta Basin deficiency fees.

Litigation

On October 19, 2017, we received notice of a request for arbitration from Sapura Energy Berhad, formerly known as SapuraKencana Petroleum Berhad, and Sapura Exploration and Production Inc., formerly known as SapuraKencana Energy Inc. (collectively, Sapura), the purchaser of our Malaysian business in February 2014. Sapura alleges that the Company owes approximately $81 million in damages for breach of contract, and further alleges, in the alternative, that Newfield owes approximately $30 million for a tax indemnity, plus interest, legal fees and other costs. We filed our response to the request for arbitration in December 2017 and have filed our statement of defense, cross-claim and other filings in the first half of 2018. We continue to be committed to fully contesting the claims and intend to vigorously defend the Company’s interest. Arbitration with the buyers of our Malaysian operations is scheduled to occur in the first half of 2019.

In May 2015, a lawsuit was filed against the Company alleging certain plugging and abandonment predecessor-in-interest liabilities related to offshore assets sold by the Company in 2010. The Company responded to the petition, denied the allegations and vigorously defended the case. The court held that the Company must bear a “portion” of the plugging and abandonment costs, but the “exact percentage” of such costs should be determined in arbitration and stayed the case pending arbitration. Through settlement negotiations surrounding the arbitration proceeding, the Company and the plaintiff reached a mutual settlement on September 23, 2016, involving a cash payment by the Company totaling $18 million. The settlement was recorded under the caption “Operating expenses — Other” on our consolidated statement of operations. On October 3, 2016, the court dismissed the case with prejudice.

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

2019) and Wilks v. Newfield Exploration Co., et al. , Case 1:19-cv-00134 (D. Del.) (Jan. 24, 2019), which Newfield and Encana refer to collectively as the “Stockholder Actions.” In general, the Stockholder Actions allege that the defendants violated Sections 14(a) and 20(a) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), or aided and abetted in such alleged violations, because the Joint Proxy Statement/Prospectus allegedly omits or misstates material information. The Stockholder Actions sought, among other things, injunctive relief preventing the consummation of the Merger, unspecified damages and attorneys’ fees.

We have been named as a defendant in a number of lawsuits and are involved in various other disputes, all arising in the ordinary course of our business, such as (a) claims from royalty owners for disputed royalty payments, (b) commercial disputes, (c) personal injury claims and (d) property damage claims. Although the outcome of these lawsuits and disputes cannot be predicted with certainty, we do not expect these matters to have a material adverse effect on our financial position, cash flows or results of operations.

13. Stockholders’ Equity Activity

Common Stock

During the first quarter of 2016, we issued 34.5 million additional shares of common stock through a public equity offering for net proceeds of approximately $776 million. A portion of the proceeds was used to acquire additional properties in the Anadarko Basin STACK play and to repay borrowings under our credit facility and money market lines of credit. The remainder was available for general corporate purposes.

Treasury Stock

Upon vesting of employee restricted stock awards and restricted stock units, we typically repurchase a portion of the vested shares for payment of employee tax withholding. Such repurchases are not part of a publicly announced program to repurchase shares of our common stock. During 2018, Newfield repurchased 633,129 shares.

14. Earnings Per Share

Basic earnings per share (EPS) is calculated by dividing net income less any applicable adjustments (the numerator) by the weighted-average number of shares of common stock (excluding unvested restricted stock and restricted stock units) outstanding during the period (the denominator). Diluted EPS incorporates the dilutive impact of outstanding stock options and unvested restricted stock and restricted stock units (using the treasury stock method). Under the treasury stock method, the amount the employee must pay for exercising stock options, the amount of unrecognized compensation expense related to unvested restricted stock awards and restricted stock units and the amount of excess tax benefits that would be recorded when the award becomes deductible are assumed to be used to repurchase shares. See Note 15, “Stock-Based Compensation.”

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following is the calculation of basic and diluted weighted-average shares outstanding and EPS for the indicated years.


	2018		2017		2016
	(In millions, except per share data)
Net income (loss)	$	817	$	427	$	(1,230	)

Weighted-average shares (denominator):
Weighted-average shares — basic		200		199		193
Dilution effect of stock options and unvested restricted stock and restricted stock units outstanding at end of period		1		1		—

Weighted-average shares — diluted		201		200		193

Excluded due to anti-dilutive effect		1		1		2
Earnings (loss) per share:
Basic	$	4.08	$	2.14	$	(6.36	)

Diluted	$	4.06	$	2.13	$	(6.36	)

15. Stock-Based Compensation

For the years ended December 31, our stock-based compensation expense consisted of the following:


	2018			2017			2016
	(In millions)
Equity awards	$	63		$	53		$	32
Liability awards		1			5			21

Total stock-based compensation expense		64			58			53
Capitalized in oil and gas properties		(8	)		(17	)		(17	)

Net stock-based compensation expense	$	56		$	41		$	36

As of December 31, 2018, we had approximately $42 million of total unrecognized stock-based compensation expense related to unvested stock-based compensation awards that vest within four years. On December 31, 2018, the last reported sales price of our common stock on the New York Stock Exchange was $14.66 per share.

During the first quarter of 2017, we changed our qualified retirement requirements for existing market-based restricted stock units and all subsequently issued equity and liability awards. An employee becomes eligible for qualified retirement based on a combination of years of service and age. Under the revised requirements, qualified retirement allows an employee to continue vesting between 50% and 100% of awards with no additional service requirement beyond a six-month notification period. This change resulted in the accelerated recognition of stock-based compensation expense for unvested market-based restricted stock units previously issued.

See Note 20, “ Encana Merger Agreement-Treatment of Newfield Equity Awards ,” for information regarding treatment of outstanding stock based compensation awards in connection with the consummation of the Merger.

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Equity Awards

Equity awards consist of service-based and market-based restricted stock and restricted stock units, stock options and stock purchase options under the Employee Stock Purchase Plan (ESPP). In May 2017, Newfield adopted the 2017 Omnibus Incentive Plan, as amended (2017 Plan), which replaced the 2011 Omnibus Stock Plan as the vehicle for granting equity-based compensation awards. The fair value of grants is determined utilizing the Black-Scholes option-pricing model for stock options and a Monte Carlo lattice-based model for our market-based restricted stock and restricted stock units. Compensation expense for equity awards is expected to be recognized on a straight-line basis over the required service periods.

Shares available for grant under our 2017 Plan are reduced by 1.67 times the number of shares of restricted stock or restricted stock units awarded under the plan and are reduced by 1 times the number of shares subject to stock options awarded under the plan. At December 31, 2018, we had approximately (1) 8.0 million shares available for issuance under our 2017 Plan if all future awards are stock options, or (2) 4.8 million shares available for issuance under our 2017 Plan if all future awards are restricted stock or restricted stock units. Thus far, all awards under our 2017 Plan have been granted as restricted stock or restricted stock units. We issue common shares on the grant date for restricted stock and on the exercise or vesting date for options and restricted stock units.

Restricted Stock and Restricted Stock Units. At December 31, 2018, approximately 2.2 million shares of non-vested restricted stock awards and restricted stock units were outstanding. These shares primarily vest over one to four years and vesting is dependent upon the recipient meeting applicable service requirements. In addition, at December 31, 2018, our employees held approximately 0.8 million shares of restricted stock units subject to performance-based vesting criteria (all of which are currently considered market-based restricted stock under authoritative accounting guidance).

The following table summarizes the activity for our restricted stock and restricted stock unit activity.


	Service- Based Shares			Weighted- Average Grant Date Fair Value per Share		Market- Based Shares			Weighted- Average Grant Date Fair Value per Share		Total Shares
	(In thousands, except per share data)
Non-vested shares outstanding at January 1, 2016		1,700		$	30.30		1,074		$	23.76		2,774
Granted		990			37.95		436			28.94		1,426
Forfeited		(217	)		29.15		(77	)		43.04		(294	)
Vested		(899	)		29.34		(574	)		21.36		(1,473	)

Non-vested shares outstanding at December 31, 2016		1,574			35.56		859			26.28		2,433
Granted		1,244			29.81		323	⁽¹⁾		39.57		1,567
Forfeited		(91	)		34.43		(55	)		37.14		(146	)
Vested		(694	)		34.67		(386	)		29.43		(1,080	)

Non-vested shares outstanding at December 31, 2017		2,033			32.41		741			38.12		2,774
Granted		1,205			26.33		835	⁽²⁾⁽³⁾		30.02		2,040
Forfeited		(135	)		31.37		(31	)		35.85		(166	)
Vested		(926	)		32.37		(785	) ⁽³⁾		28.94		(1,711	)

Non-vested shares outstanding at December 31, 2018		2,177		$	29.13		760		$	38.80		2,937

(1)	In February 2017, we granted approximately 323,000 restricted stock units, which based on achievement of certain criteria, could vest within a range of 0% to 200% of shares granted upon completion of the period ending December 31, 2019.

(2)	In February 2018, we granted approximately 464,000 restricted stock units, which based on achievement of certain criteria, could vest within a range of 0% to 200% of shares granted upon completion of the period ending December 31, 2020.

(3)

In December 2018, the 2016 market-based restricted stock units outstanding vested at 200%. Accordingly, an additional 371,000 units have been included in both the granted and vested lines in 2018. As the shares vested at 200% instead of the amount that otherwise would have vested in accordance with the original award terms, this represents a type III modification resulting in an additional $11.3 million of expense which was recognized in December 2018.

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The total fair value of all restricted stock and restricted stock units that vested during the years ended December 31, 2018, 2017 and 2016 was $53 million, $35 million and $39 million, respectively.

Stock Options. As of December 31, 2018, we had no stock options outstanding and exercisable. All outstanding stock options expired in January 2018. No stock options have been granted since 2008, except for ESPP options as discussed in the Employee Stock Purchase Plan section below.

The following table provides information about outstanding stock options.


	Number of Shares Underlying Options		Weighted-Average Exercise Price per Share		Weighted-Average Remaining Contractual Life		Aggregate Intrinsic Value ⁽¹⁾
	(In thousands)				(In years)		(In millions)
Outstanding and exercisable at:
December 31, 2016		177	$	48.45		1.1	$	—
December 31, 2017		155		48.45		0.1		—
December 31, 2018		—		—		0.0		—

(1)	The intrinsic value of a stock option is the amount by which the market value of our common stock at the indicated date, or at the time of exercise, exceeds the exercise price of the option.

Employee Stock Purchase Plan. In May 2010, our stockholders approved the Newfield Exploration Company 2010 Employee Stock Purchase Plan with one million shares of our common stock available for issuance. In May 2017, our stockholders approved the amended and restated ESPP, increasing the number of our common stock available for issuance by an additional two million shares. Pursuant to our employee stock purchase plan, for each six-month period beginning on January 1 or July 1 during the plan term, each eligible employee has the opportunity to purchase our common stock for a purchase price equal to 85% of the lesser of the fair market value of our common stock on the first or last day of the period. Each employee may purchase up to $25,000 in common stock per calendar year. Employees of our China business are not eligible to participate in the plan. At December 31, 2018, approximately two million shares of our common stock remained available for issuance under the current plan.

The fair value of the options granted was determined using the Black-Scholes option valuation method assuming no dividends and an expected life of six months. For the years ended December 31, our ESPP issuances and valuation assumptions consisted of the following:


	Options Issued		Weighted- Average Fair Value per Share		Risk-free Interest Rate			Weighted- Average Volatility
	(In thousands)
2016		99	$	10.51		0.43	%		47.94	%
2017		124		9.03		0.87			39.13
2018		119		8.31		1.84			40.81

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Liability Awards

Liability awards consist of service-based awards that are settled in cash instead of shares, as discussed below.

Cash-Settled Restricted Stock Units. The value of the cash-settled restricted stock units, and the associated stock-based compensation expense, is based on the Company’s stock price at the end of each period. As of December 31, 2018, we had a liability of $3 million related to these awards. The following table provides information about cash-settled restricted stock unit activity.


	Cash-Settled Restricted Stock Units
	(In thousands)
Non-vested units outstanding at January 1, 2016		708
Granted		299
Forfeited		(101	)
Vested		(446	)

Non-vested units outstanding at December 31, 2016		460
Granted		241
Forfeited		(32	)
Vested		(318	)

Non-vested units outstanding at December 31, 2017		351
Granted		186
Forfeited		(21	)
Vested		(218	)

Non-vested units outstanding at December 31, 2018		298

16. Employee Benefit Plans

Post-Retirement Medical Plan

We sponsor a post-retirement medical plan that covers all eligible retired employees until they reach age 65. An employee may become eligible upon reaching age 55 and providing 5 years of service. At December 31, 2018, both our accumulated benefit obligation and our accrued benefit costs were $24 million. Our net periodic benefit cost was approximately $3 million for each of the years ended December 31, 2018, 2017 and 2016.

The expected future benefit payments under our post-retirement medical plan for the next ten years include $11 million for the five-year period 2018 through 2022 and $11 million for the five-year period 2023 through 2027.

Annual Cash Incentive Compensation Plan

During 2010, our Board of Directors, with the recommendation of the Compensation & Management Development Committee, approved a new annual cash incentive compensation plan for all employees (the 2011 Annual Incentive Plan). Under the 2011 Annual Incentive Plan, the Compensation & Management Development Committee determines the annual award pool for all employees based upon a number of factors including the Company’s performance against stated performance goals and in comparison with peer companies in our industry. All employees are eligible if employed on October 1 and December 31 of the performance period. Beginning with the year ended December 31, 2010, our annual cash incentive compensation is paid in a single payment to employees during the first quarter after the performance period ends.

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Total incentive compensation expense under the 2011 Annual Incentive Plan for the years ended December 31, 2018, 2017 and 2016 was $35 million, $31 million and $35 million, respectively.

401(k) and Deferred Compensation Plans

We sponsor a 401(k) profit sharing plan under Section 401(k) of the Internal Revenue Code. This plan covers all of our employees, excluding those of our foreign subsidiaries. We match $1.00 for each $1.00 of employee deferral, with our contribution not to exceed 8% of an employee’s salary, subject to limitations imposed by the IRS. We also sponsor a highly compensated employee deferred compensation plan. This non-qualified plan allows an eligible employee to defer a portion of his or her salary or bonus on an annual basis. We match $1.00 for each $1.00 of employee deferral, with our contribution not to exceed 8% of an employee’s salary, subject to limitations imposed by the plan. Our contribution with respect to each participant in the deferred compensation plan is reduced by the amount of contribution made by us to our 401(k) plan for that participant. Our combined contributions to these two plans were $6 million for each of the years ended December 31, 2018, 2017 and 2016.

17. Restructuring Costs

In April 2015 and May 2016, we announced plans to consolidate and reorganize domestic operating functions to our headquarters in The Woodlands, Texas, which resulted in a reduction of employees and closure of our offices in Denver, Colorado; North Houston (Greenspoint), Texas; and Tulsa, Oklahoma. Our decision to restructure the organization was primarily in response to the oil and gas commodity price environment.

Restructuring costs recorded in our consolidated statement of operations for the years ended December 31 are set forth below.


Type of Restructuring Cost	Location in the Consolidated Statement of Operations	2018		2017		2016
		(In millions)
Severance and related benefit costs	Operating expenses—General and administrative	$	—	$	—	$	17
Relocation costs	Operating expenses—General and administrative		—		2		5
Office-lease abandonment costs	Operating expenses—General and administrative		—		—		6
Other associated costs	Operating expenses—Depreciation, depletion and amortization		—		—		—

Total		$	—	$	2	$	28

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table summarizes our restructuring costs and related liability.


	Severance and Related Benefit Costs			Office-lease Abandonment Costs ⁽¹⁾			Relocation Costs			Other Associated Costs		Total
	(In millions)
Restructuring liability at January 1, 2016	$	1		$	13		$	—		$	—	$	14
Additions		17			3			5			—		25
Settlements		(17	)		(5	)		(5	)		—		(27	)
Revisions		—			3			—			—		3

Restructuring liability at December 31, 2016	$	1		$	14		$	—		$	—	$	15

Cumulative costs as of December 31, 2016	$	24		$	20		$	10		$	1	$	55

Restructuring liability at January 1, 2017	$	1		$	14		$	—		$	—	$	15
Additions		—			—			2			—		2
Settlements		(1	)		(6	)		(2	)		—		(9	)
Revisions		—			—			—			—		—

Restructuring liability at December 31, 2017	$	—		$	8		$	—		$	—	$	8

Cumulative costs as of December 31, 2017	$	24		$	20		$	12		$	1	$	57

Restructuring liability at January 1, 2018	$	—		$	8		$	—		$	—	$	8
Additions		—			—			—			—		—
Settlements		—			(5	)		—			—		(5	)
Revisions		—			—			—			—		—

Restructuring liability at December 31, 2018	$	—		$	3		$	—		$	—	$	3

Cumulative costs as of December 31, 2018	$	24		$	20		$	12		$	1	$	57

Expected total costs	$	24		$	20		$	12		$	1	$	57

(1)	The office-lease abandonment liability will be relieved as lease payments are made and sublease income is received over the life of the lease ending 2022.

18. Segment Information

While we have operations in the oil and gas exploration and production industry, we are organizationally structured along geographic operating segments. Our current operating segments are the United States and China. The accounting policies of our operating segments are the same as those described in Note 1, “Organization and Summary of Significant Accounting Policies.”

The following tables provide the geographic operating segment information for the years ended December 31, 2018, 2017 and 2016.

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	Domestic		China		Total
	(In millions)
Year Ended December 31, 2018:
Revenues
Oil	$	1,639	$	108	$	1,747
Gas		424		—		424
NGL		459		—		459

Oil, gas and NGL revenues	$	2,522	$	108	$	2,630
Lease operating		241		28		269
Transportation and processing		348		—		348
Production and other taxes		123		2		125
Depreciation, depletion and amortization		608		20		628

Results of operations for oil and gas producing activities before tax		1,202		58		1,260
Other revenues		13		—		13
General and administrative		225		6		231
Other		11		1		12
Allocated income tax (benefit) ⁽¹⁾		250		23

Net income (loss) from oil and gas properties	$	729	$	28

Total revenues						2,643
Total operating expenses						1,613

Income (loss) from operations						1,030
Interest expense, net of interest income, capitalized interest and other						(88	)
Commodity derivative income (expense)						(101	)

Income (loss) from operations before income taxes					$	841
Total assets	$	5,737	$	81	$	5,818

Additions to long-lived assets	$	1,518	$	—	$	1,522

(1)	Allocated income tax based on estimated combined federal and state statutory tax rates in effect during the period, comprised of 25.5% for domestic and 46% for China.

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	Domestic		China		Total
	(In millions)
Year Ended December 31, 2017:
Revenues
Oil	$	1,028	$	86	$	1,114
Gas		339		—		339
NGL		312		—		312

Oil, gas and NGL revenues	$	1,679	$	86	$	1,765
Lease operating		188		27		215
Transportation and processing		300		—		300
Production and other taxes		64		—		64
Depreciation, depletion and amortization		443		24		467

Results of operations for oil and gas producing activities before tax		684		35		719
Other revenues		2		—		2
General and administrative		194		6		200
Other		5		1		6
Allocated income tax (benefit) ⁽¹⁾		180		17

Net income (loss) from oil and gas properties	$	307	$	11

Total revenues						1,767
Total operating expenses						1,252

Income (loss) from operations						515
Interest expense, net of interest income, capitalized interest and other						(82	)
Commodity derivative income (expense)						(47	)

Income (loss) from operations before income taxes					$	386

Total assets	$	4,875	$	86	$	4,961

Additions to long-lived assets	$	1,288	$	1	$	1,289

(1)	Allocated income tax based on estimated combined federal and state statutory tax rates in effect during the period, comprised of 37% for domestic and 60% for China.

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	Domestic			China			Total
	(In millions)
Year Ended December 31, 2016:
Revenues
Oil	$	763		$	217		$	980
Gas		284			—			284
NGL		204			—			204

Oil, gas and NGL revenues	$	1,251		$	217		$	1,468
Lease operating		189			55			244
Transportation and processing		272			—			272
Production and other taxes		41			1			42
Depreciation, depletion and amortization		458			114			572
Ceiling test and other impairments		962			66			1,028

Results of operations for oil and gas producing activities before tax		(671	)		(19	)		(690	)
Other revenues		4			—			4
General and administrative		205			8			213
Other		20			—			20
Allocated income tax (benefit) ⁽¹⁾		(330	)		(16	)

Net income (loss) from oil and gas properties	$	(562	)	$	(11	)

Total revenues								1,472
Total operating expenses								2,391

Income (loss) from operations								(919	)
Interest expense, net of interest income, capitalized interest and other								(98	)
Commodity derivative income (expense)								(191	)

Income (loss) from operations before income taxes							$	(1,208	)

Total assets	$	4,166		$	146		$	4,312

Additions to long-lived assets	$	1,369		$	2		$	1,371

(1)	Allocated income tax based on estimated combined federal and state statutory tax rates in effect during the period, comprised of 37% for domestic and 60% for China.

19. Supplemental Cash Flow Information

The following table presents information about supplemental cash flows for each of the three years ended December 31:


	2018			2017			2016
	(In millions)
Cash Payments:
Interest payments	$	79		$	84		$	97
Income tax payments (refunds)		(51	)		(2	)		17
Non-cash investing and financing activities excluded from the statement of cash flows:
(Increase) decrease in receivables for property sales	$	—		$	—		$	6
(Increase) decrease in accrued capital expenditures		12			(81	)		33
(Increase) decrease in asset retirement costs		6			31			46

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

20. Encana Merger Agreement

On October 31, 2018, the Company entered into the Merger Agreement, with Encana and Merger Sub, pursuant to which Merger Sub will merge with and into the Company, with the Company surviving the Merger as a wholly-owned subsidiary of Encana.

The Merger Agreement provides, subject to the terms and conditions of the Merger Agreement, at the effective time of the Merger (the “Effective Time”), each outstanding share of capital stock, par value $0.01 per share, of Newfield shall automatically be converted into the right to receive 2.6719 common shares, no par value, of Encana, as well as cash in lieu of any fractional shares of Encana that would otherwise have been issued (collectively, the Merger Consideration).

Newfield and Encana intend that, for U.S. federal (and applicable state and local) income tax purposes, the Merger will be treated as a taxable acquisition of Newfield common stock by an indirect subsidiary of Encana.

The Company’s credit agreements terminate upon closing of the transaction and any outstanding borrowings become due at that time. The Company’s senior notes will remain outstanding as Encana has agreed to guarantee those indentures, which is allowed under the indenture agreements.

Treatment of Newfield Equity Awards

The Merger Agreement provides that: (i) all outstanding Newfield restricted stock awards will be cancelled and each holder of Newfield restricted stock awards will be entitled to receive, on a fully vested basis, the Merger Consideration; (ii) all outstanding Newfield restricted stock units will be cancelled and (a) each holder of Newfield restricted stock units that have a cash settlement feature will be entitled to receive, on a fully vested basis, a cash payment of equivalent value to the Merger Consideration, based on the volume weighted averages of the trading price of Encana common shares on each of the five consecutive trading days ending on the trading day that is three trading days prior to the Effective Time (the Encana Trading Price) and (b) each holder of Newfield restricted stock units that have a share settlement feature will be entitled to receive, on a fully vested basis, the Merger Consideration; (iii) all outstanding Newfield performance share units will be cancelled and will convert into the right to receive the Merger Consideration, with the performance-based vesting conditions applicable to such Newfield performance stock units deemed achieved based on the determination of the compensation and management committee of the Newfield board of directors, not to exceed 200% per Newfield performance share unit; and (iv) any shares of Newfield notional stock held in connection with Newfield’s Nonqualified Deferred Compensation Plan will convert into the right to receive a cash payment of equivalent value to the Merger Consideration, based on the Encana Trading Price.

Conditions to the Merger

The completion of the Merger is subject to various customary closing conditions, including, among other things, (i) the receipt of certain approvals of the Newfield stockholders and the Encana shareholders, (ii) the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, (iii) the effectiveness of the registration statement on Form S-4 that Encana is obligated to file with the Securities and Exchange Commission (SEC) in connection with the issuance of Encana common shares in the Merger, (iv) the authorization for listing of Encana common shares to be issued in the Merger on the New York Stock Exchange and the Toronto Stock Exchange, (v) the accuracy of each party’s representations and warranties (subject to certain materiality qualifiers) and compliance by each party with its covenants under the Merger Agreement in all material respects and (vi) the absence of legal restraints prohibiting or restraining the Merger.

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Litigation Related to the Pending Merger

In connection with the Merger Agreement and the transactions contemplated thereby, six purported class action complaints were filed on behalf of Newfield stockholders against Newfield, members of the Newfield board of directors, and, in one complaint, Encana and Merger Sub in the United States District Courts for the District of Delaware and the Southern District of New York. The six complaints are captioned as follows: Stein v. Newfield Exploration Co., et al. , Case 1:18-cv-02001 (D. Del.) (Dec. 17, 2018), Franchi v. Newfield Exploration Co., et al. , Case 1:18-cv-02020 (D. Del.) (Dec. 19, 2018), Booth Family Trust v. Newfield Exploration Co., et al. , Case 1:18-cv-02056 (D. Del.) (Dec. 27, 2018), Clay v. Newfield Exploration Co., et al. , Case 1:19-cv-00018 (S.D.N.Y.) (Jan. 2, 2019), Farias v. Newfield Exploration Co., et al. , Case 1:19-cv-00059 (D. Del.) (Jan. 9, 2019) and Wilks v. Newfield Exploration Co., et al. , Case 1:19-cv-00134 (D. Del.) (Jan. 24, 2019), which Newfield and Encana refer to collectively as the “Stockholder Actions.” In general, the Stockholder Actions allege that the defendants violated Sections 14(a) and 20(a) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), or aided and abetted in such alleged violations, because the Joint Proxy Statement/Prospectus allegedly omits or misstates material information. The Stockholder Actions sought, among other things, injunctive relief preventing the consummation of the Merger, unspecified damages and attorneys’ fees.

21. Subsequent Events

On February 12, 2019 shareholders of Encana Corporation and Newfield Exploration approved the proposals necessary for the companies planned strategic combination at special shareholder meetings.

On February 13, 2019 Encana closed on the acquisition of the Company in an all-stock transaction, with the Company surviving the Merger as a wholly-owned subsidiary of Encana.

See Note 20, “ Encana Merger Agreement ” for additional details regarding the merger.

NEWFIELD EXPLORATION COMPANY

SUPPLEMENTARY FINANCIAL INFORMATION

SUPPLEMENTARY OIL AND GAS DISCLOSURES — UNAUDITED

Costs Incurred

The following tables present costs incurred for oil and gas property acquisitions, exploration and development for the respective years:


	Domestic		China			Total
	(In millions)
2018:
Property acquisitions:
Unproved	$	39	$	—		$	39
Proved		11		—			11
Exploration		664		—			664
Development		774		(2	)		772

Total costs incurred ⁽¹⁾	$	1,488	$	(2	)	$	1,486

2017:
Property acquisitions:
Unproved	$	98	$	—		$	98
Proved		104		—			104
Exploration		704		—			704
Development		430		5			435

Total costs incurred ⁽¹⁾	$	1,336	$	5		$	1,341

2016:
Property acquisitions:
Unproved	$	491	$	1		$	492
Proved		88		—			88
Exploration		535		—			535
Development		210		15			225

Total costs incurred ⁽¹⁾	$	1,324	$	16		$	1,340

(1)	Includes net changes in asset retirement costs of $(4) million, $(20) million and $(8) million for 2018, 2017 and 2016, respectively.

NEWFIELD EXPLORATION COMPANY

SUPPLEMENTARY FINANCIAL INFORMATION

SUPPLEMENTARY OIL AND GAS DISCLOSURES — UNAUDITED — (Continued)

Capitalized Costs

Capitalized costs for our oil and gas producing activities consisted of the following:


	Domestic			China			Total
	(In millions)
December 31, 2018:
Proved properties	$	24,246		$	631		$	24,877
Unproved properties		1,043			—			1,043

		25,289			631			25,920
Accumulated depreciation, depletion and amortization		(10,200	)		(437	)		(10,637	)
Accumulated impairment		(10,325	)		(184	)		(10,509	)

Net capitalized costs	$	4,764		$	10		$	4,774

December 31, 2017:
Proved properties	$	22,638		$	634		$	23,272
Unproved properties		1,200			—			1,200

		23,838			634			24,472
Accumulated depreciation, depletion and amortization		(9,614	)		(418	)		(10,032	)
Accumulated impairment		(10,325	)		(184	)		(10,509	)

Net capitalized costs	$	3,899		$	32		$	3,931

Items reducing the capitalized costs of our oil and gas properties which are not included in total costs incurred are as follows:


	2018		2017
	(In millions)
Property sales — Domestic	$	36	$	65
Property sales — Domestic asset retirement costs		1		3
Property sales — China		—		31
Property sales — China asset retirement costs		—		7
Ceiling test impairment — Domestic		—		—
Ceiling test impairment — China		—		—

	$	37	$	106

Reserves

Users of this information should be aware that the process of estimating quantities of proved and proved developed oil and gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir also may change substantially over time as a result of numerous factors, including additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates may occur from time to time.

Reserves Estimates. All reserve information in this report is based on estimates prepared by our petroleum engineering staff and is the responsibility of management. The preparation of our oil and gas reserves estimates is completed in accordance with our prescribed internal control procedures, which include verification of data input into our reserves forecasting and economics evaluation software, as well as multi-discipline management reviews. The technical employee responsible for overseeing the preparation of the reserves estimates has a Bachelor of Science in Petroleum Engineering, with more than 40 years of industry experience (including over 22 years of experience in reserve estimation).

NEWFIELD EXPLORATION COMPANY

SUPPLEMENTARY FINANCIAL INFORMATION

SUPPLEMENTARY OIL AND GAS DISCLOSURES — UNAUDITED — (Continued)

Our reserves estimates use available geological and reservoir data as well as production performance data. Our petroleum engineering staff review estimates annually with management and revise the estimates, either upward or downward, as warranted by available data. The data reviewed includes, among other things, seismic data, well logs, production tests, reservoir pressures and individual well and field performance data. The data incorporated into our interpretations includes structure and isopach maps, individual well and field performance and other engineering and geological work products such as material balance calculations and reservoir simulation to arrive at conclusions about individual well and field projections. Additionally, offset performance data, operating expenses, capital costs and product prices factor into estimating quantities of reserves. Revisions are necessary due to changes in, among other things, reservoir performance, prices, economic conditions and governmental regulations, as well as changes in the expected recovery rates associated with development drilling. Sustained decreases in prices, for example, may cause a reduction in some reserves due to reaching economic limits sooner.

Reserves Activity Overview. The following is a discussion of our proved reserves and reserve additions and revisions.


	Year Ended December 31,
	2018			2017			2016
	(MMBOE)
Proved Reserves:
Beginning of year		680			513			509
Reserve additions		101			76			77
Reserve revisions		76			153			21
Sales of properties		(5	)		(4	)		(35	)
Production		(72	)		(58	)		(59	)

End of year		780			680			513

During 2018, our proved reserves increased 100 MMBOE primarily as a result of positive performance revisions of 66 MMBOE and revisions of 10 MMBOE resulting from commodity price increases. During 2018, we added proved reserves of 101 MMBOE, which included 2 MMBOE of reserves purchased and 99 MMBOE added through extensions, discoveries and other additions. We also sold non-strategic assets of 5 MMBOE and produced 72 MMBOE.

During 2017, our proved reserves increased 167 MMBOE primarily as a result of positive performance revisions of 139 MMBOE and revisions of 14 MMBOE resulting from commodity price increases. During 2017, we added proved reserves of 76 MMBOE, which included 2 MMBOE of reserves purchased and 74 MMBOE added through extensions, discoveries and other additions. We also sold non-strategic assets of 4 MMBOE and produced 58 MMBOE.

During 2016, our proved reserves increased 4 MMBOE primarily as a result of positive performance revisions of 36 MMBOE and cost structure improvement revisions of 7 MMBOE. Performance revisions and cost structure improvements were partially offset by negative revisions of 22 MMBOE resulting from commodity price decreases. During 2016, we added proved reserves of 77 MMBOE, which included 35 MMBOE of reserves purchased and 42 MMBOE added through extensions, discoveries and other additions. We also sold non-strategic assets of 35 MMBOE and produced 59 MMBOE.

NEWFIELD EXPLORATION COMPANY

SUPPLEMENTARY FINANCIAL INFORMATION

SUPPLEMENTARY OIL AND GAS DISCLOSURES — UNAUDITED — (Continued)

Estimated Net Quantities of Proved Oil and Gas Reserves

The following table sets forth our total net proved reserves and our total net proved developed and undeveloped reserves as of December 31, 2015, 2016, 2017 and 2018 and the changes in our total net proved reserves during the three-year period ended December 31, 2018:


	Crude Oil and Condensate (MMBbls)									Natural Gas (Bcf)
	Domestic			China ⁽¹⁾			Total			Domestic			China ⁽¹⁾		Total
*Proved developed and undeveloped reserves as of:*
December 31, 2015		197			10			207			1,305			—		1,305
Revisions of previous estimates		(9	)		—			(9	)		116			—		116
Extensions, discoveries and other additions		19			—			19			92			—		92
Purchases of properties		12			—			12			90			—		90
Sales of properties		(13	)		—			(13	)		(102	)		—		(102	)
Production		(21	)		(5	)		(26	)		(135	)		—		(135	)

December 31, 2016		185			5			190			1,366			—		1,366
Revisions of previous estimates		50			2			52			318			—		318
Extensions, discoveries and other additions		35			—			35			151			—		151
Purchases of properties		1			—			1			2			—		2
Sales of properties		(1	)		(3	)		(4	)		(3	)		—		(3	)
Production		(22	)		(2	)		(24	)		(130	)		—		(130	)

December 31, 2017		248			2			250			1,704			—		1,704
Revisions of previous estimates		(5	)		1			(4	)		211			—		211
Extensions, discoveries and other additions		50			—			50			190			—		190
Purchases of properties		1			—			1			1			—		1
Sales of properties		(3	)		—			(3	)		(6	)		—		(6	)
Production		(26	)		(2	)		(28	)		(165	)		—		(165	)

December 31, 2018		265			1			266			1,935			—		1,935

*Proved developed reserves as of:*
December 31, 2015		115			10			125			942			—		942
December 31, 2016		104			5			109			928			—		928
December 31, 2017		136			2			138			1,099			—		1,099
December 31, 2018		148			1			149			1,262			—		1,262
*Proved undeveloped reserves as of:*
December 31, 2015		82			—			82			363			—		363
December 31, 2016		81			—			81			438			—		438
December 31, 2017		112			—			112			605			—		605
December 31, 2018		117			—			117			673			—		673

(1)	All of our reserves in China are associated with production sharing contracts and are calculated using the economic interest method.

NEWFIELD EXPLORATION COMPANY

SUPPLEMENTARY FINANCIAL INFORMATION

SUPPLEMENTARY OIL AND GAS DISCLOSURES — UNAUDITED — (Continued)

Estimated Net Quantities of Proved Oil and Gas Reserves — (Continued)


	NGLs (MMBbls)								Total (MMBOE)
	Domestic			China ⁽¹⁾		Total			Domestic			China ⁽¹⁾			Total
*Proved developed and undeveloped reserves as of:*
December 31, 2015		84			—		84			499			10			509
Revisions of previous estimates		13			—		13			21			—			21
Extensions, discoveries and other additions		8			—		8			42			—			42
Purchases of properties		7			—		7			35			—			35
Sales of properties		(6	)		—		(6	)		(35	)		—			(35	)
Production		(11	)		—		(11	)		(54	)		(5	)		(59	)

December 31, 2016		95			—		95			508			5			513
Revisions of previous estimates		49			—		49			151			2			153
Extensions, discoveries and other additions		14			—		14			74			—			74
Purchases of properties		—			—		—			2			—			2
Sales of properties		—			—		—			(1	)		(3	)		(4	)
Production		(12	)		—		(12	)		(56	)		(2	)		(58	)

December 31, 2017		146			—		146			678			2			680
Revisions of previous estimates		44			—		44			75			1			76
Extensions, discoveries and other additions		17			—		17			99			—			99
Purchases of properties		—			—		—			2			—			2
Sales of properties		—			—		—			(5	)		—			(5	)
Production		(16	)		—		(16	)		(70	)		(2	)		(72	)

December 31, 2018		191			—		191			779			1			780

*Proved developed reserves as of:*
December 31, 2015		47			—		47			319			10			329
December 31, 2016		50			—		50			309			5			314
December 31, 2017		78			—		78			398			2			400
December 31, 2018		108			—		108			466			1			467
*Proved undeveloped reserves as of:*
December 31, 2015		37			—		37			180			14			194
December 31, 2016		45			—		45			199			—			199
December 31, 2017		68			—		68			280			—			280
December 31, 2018		83			—		83			313			—			313

(1)	All of our reserves in China are associated with production sharing contracts and are calculated using the economic interest method.

NEWFIELD EXPLORATION COMPANY

SUPPLEMENTARY FINANCIAL INFORMATION

SUPPLEMENTARY OIL AND GAS DISCLOSURES — UNAUDITED — (Continued)

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

The standardized measure of discounted future net cash flows from our estimated proved oil and gas reserves is as follows:


	Domestic			China			Total
	(In millions)
December 31, 2018:
Future cash inflows	$	26,132		$	105		$	26,237
Less related future:
Production costs		(10,552	)		(49	)		(10,601	)
Development and abandonment costs		(3,870	)		(13	)		(3,883	)

Future net cash flows before income taxes		11,710			43			11,753
Future income tax expense		(1,653	)		—			(1,653	)

Future net cash flows before 10% discount		10,057			43			10,100
10% annual discount for estimating timing of cash flows		(4,646	)		(3	)		(4,649	)

Standardized measure of discounted future net cash flows	$	5,411		$	40		$	5,451

December 31, 2017:
Future cash inflows	$	20,346		$	120		$	20,466
Less related future:
Production costs		(8,193	)		(53	)		(8,246	)
Development and abandonment costs		(2,786	)		(16	)		(2,802	)

Future net cash flows before income taxes		9,367			51			9,418
Future income tax expense		(1,091	)		—			(1,091	)

Future net cash flows before 10% discount		8,276			51			8,327
10% annual discount for estimating timing of cash flows		(3,922	)		(4	)		(3,926	)

Standardized measure of discounted future net cash flows	$	4,354		$	47		$	4,401

December 31, 2016:
Future cash inflows	$	11,778		$	220		$	11,998
Less related future:
Production costs		(5,191	)		(96	)		(5,287	)
Development and abandonment costs		(1,993	)		(44	)		(2,037	)

Future net cash flows before income taxes		4,594			80			4,674
Future income tax expense		(207	)		—			(207	)

Future net cash flows before 10% discount		4,387			80			4,467
10% annual discount for estimating timing of cash flows		(1,867	)		(16	)		(1,883	)

Standardized measure of discounted future net cash flows	$	2,520		$	64		$	2,584

NEWFIELD EXPLORATION COMPANY

SUPPLEMENTARY FINANCIAL INFORMATION

SUPPLEMENTARY OIL AND GAS DISCLOSURES — UNAUDITED — (Continued)

Set forth in the table below is a summary of the changes in the standardized measure of discounted future net cash flows for our proved oil and gas reserves during each of the years in the three-year period ended December 31, 2018:


	Domestic			China			Total
	(In millions)
2018:
Beginning of the period	$	4,354		$	47		$	4,401
Revisions of previous estimates:
Changes in prices and costs		665			30			695
Changes in quantities		764			28			792
Changes in future development costs		(634	)		3			(631	)
Previously estimated development costs incurred during the period		777			1			778
Additions to proved reserves resulting from extensions, discoveries and improved recovery, less related costs		879			—			879
Purchases and sales of reserves in place, net		(16	)		—			(16	)
Accretion of discount		469			3			472
Sales of oil and gas, net of production costs		(1,810	)		(78	)		(1,888	)
Net change in income taxes		(367	)		—			(367	)
Production timing and other		330			6			336

Net increase (decrease)		1,057			(7	)		1,050

End of period	$	5,411		$	40		$	5,451

2017:
Beginning of the period	$	2,520		$	64		$	2,584
Revisions of previous estimates:
Changes in prices and costs		1,393			(9	)		1,384
Changes in quantities		1,387			42			1,429
Changes in future development costs		(728	)		13			(715	)
Previously estimated development costs incurred during the period		456			1			457
Additions to proved reserves resulting from extensions, discoveries and improved recovery, less related costs		658			—			658
Purchases and sales of reserves in place, net		21			(46	)		(25	)
Accretion of discount		247			6			253
Sales of oil and gas, net of production costs		(1,127	)		(59	)		(1,186	)
Net change in income taxes		(444	)		—			(444	)
Production timing and other		(29	)		35			6

Net increase (decrease)		1,834			(17	)		1,817

End of period	$	4,354		$	47		$	4,401

2016:
Beginning of the period	$	2,554		$	222		$	2,776
Revisions of previous estimates:
Changes in prices and costs		(481	)		(27	)		(508	)
Changes in quantities		153			4			157
Changes in future development costs		186			2			188
Previously estimated development costs incurred during the period		228			—			228
Additions to proved reserves resulting from extensions, discoveries and improved recovery, less related costs		418			—			418
Purchases and sales of reserves in place, net		135			—			135
Accretion of discount		235			16			251
Sales of oil and gas, net of production costs		(749	)		(161	)		(910	)
Net change in income taxes		63			—			63
Production timing and other		(222	)		8			(214	)

Net increase (decrease)		(34	)		(158	)		(192	)

End of period	$	2,520		$	64		$	2,584

Exhibit 99.3

UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL STATEMENTS OF ENCANA AND NEWFIELD FOR THE YEAR ENDED DECEMBER 31, 2018

The following unaudited pro forma condensed combined financial statements give effect to the business combination of Encana Corporation (“Encana”) and Newfield Exploration Company (“Newfield”). The merger will be accounted for using the acquisition method of accounting with Encana identified as the acquirer. Under the acquisition method of accounting, Encana will record all assets acquired and liabilities assumed at their respective acquisition date fair values at the effective time of the merger.

The acquisition method of accounting is dependent upon certain valuations and other studies that are underway but have yet to progress to a stage where there is sufficient information for a definitive measure. The sources and amounts of merger transaction expenses may also differ from that assumed in the following pro forma adjustments. Accordingly, the pro forma adjustments are preliminary, have been made solely for the purpose of providing pro forma financial statements, and are subject to revision based on a final determination of fair values as of the date of acquisition. Differences between these preliminary estimates and the final acquisition accounting may have a material impact on the accompanying pro forma financial statements and the combined company’s future results of operations and financial position.

The unaudited pro forma condensed combined financial statements are derived from the historical consolidated financial statements of Encana and Newfield, adjusted to reflect the merger of Encana and Newfield. Certain of Newfield’s historical amounts have been reclassified to conform to Encana’s financial statement presentation. The unaudited pro forma combined balance sheet as of December 31, 2018 gives effect to the merger as if the merger had been completed on December 31, 2018. The unaudited pro forma combined statement of earnings for the year ended December 31, 2018 gives effect to the merger as if the merger had been completed on January 1, 2018.

The unaudited pro forma combined financial statements reflect the following merger-related pro forma adjustments, based on available information and certain assumptions that Encana believes are reasonable:

•

the merger, including the issuance of Encana common shares as merger consideration, will be accounted for using the acquisition method of accounting, with Encana identified as the acquirer;

•

the exchange of Newfield’s outstanding equity awards, including time-based restricted stock units, restricted stock awards and performance-based restricted stock units, for Encana common shares;

•

the exchange of Newfield’s outstanding liability awards, including cash-settled time-based restricted stock units and notional stock under Newfield’s non-qualified deferred compensation plan, for cash based on the value of notional Encana common shares;

•

the assumption of liabilities for transaction-related expenses; and

•

the recognition of estimated tax impacts of the pro forma adjustments.

Assumptions and estimates underlying the pro forma adjustments are described in the accompanying notes, which should be read in conjunction with the unaudited pro forma combined financial statements. In Encana’s opinion, all adjustments that are necessary to present fairly the pro forma information have been made.

The unaudited pro forma combined financial information is provided for illustrative purposes only and are not intended to represent what Encana’s financial position or results of operations would have been had the merger actually been consummated on the assumed dates nor is it indicative of Encana’s future financial position or results of operations. The unaudited pro forma combined financial information does not reflect future events that may occur after the merger, including, but not limited to, the anticipated realization of ongoing savings from potential operating efficiencies, asset dispositions, cost savings or economies of scale that the combined company may achieve with respect to the combined operations. As a result, future results may vary significantly from the pro forma results reflected herein.

The unaudited pro forma condensed combined financial statements should be read in conjunction with the audited consolidated financial statements and accompanying notes contained in Encana’s Annual Report and on Form 10-K for the year ended December 31, 2018 and Newfield’s audited consolidated financial statements and accompanying notes contained in Exhibit 99.2 of this Current Report on Form 8-K.


	Unaudited Pro Forma Condensed Combined Balance Sheet
	As of December 31, 2018
							Pro Forma Adjustments
($ millions, except per share amounts)	Encana Historical			Newfield Historical			Reclassification Adjustment (Note 2a)			Acquisition Adjustment (Note 2)					Transaction Adjustment (Note 2)					Pro Forma Combined
Assets
Current Assets
Cash and cash equivalents		1,058			292			—			—					(5	)	b	)		1,345
Accounts receivables and accrued revenues		789			374			10			—					—					1,173
Inventories		—			24			(24	)		—					—					—
Risk Management		554			12			—			—					—					566
Income tax receivable		275			—			24			—					—					299
Other current assets		—			61			(24	)		—					—					37

Total Current Assets		2,676			763			(14	)		—					(5	)				3,420
Property, Plant and Equipment, at cost:
Oil and natural gas properties, based on full cost accounting
Oil and gas properties, net		—			4,774			—			(4,774	)	c	)		—					—
Proved properties		41,241			—			94			5,592		c	)		—					46,927
Unproved properties		3,730			—			—			746		c	)		—					4,476
Other		2,122			172			(75	)		(43	)	c	)		—					2,176

Property, plant and equipment		47,093			4,946			19			1,521		c	)		—					53,579
Less: Accumulated depreciation, depletion and amortization		(38,121	)		—			—			—					—					(38,121	)

Property, plant and equipment, net		8,972			4,946			19			1,521		c	)		—					15,458
Other Assets		147			37			17			(11	)	d	)		—					190
Risk Management		161			—			—			—					—					161
Investments		—			22			(22	)		—					—					—
Restricted cash		—			50			—			—					—					50
Deferred Income Taxes		835			—			—			(225	)	c	)		—					610
Goodwill		2,553			—			—			13		c	)		—					2,566

Total Assets		15,344			5,818			—			1,298					(5	)				22,455
Liabilities and Shareholders’ Equity
Current Liabilities
Accounts payable and accrued liabilities		1,490			57			748			—					90		e	)		2,385
Accrued liabilities		—			665			(665	)		—					—					—
Advances from joint owners		—			83			(83	)		—					—					—
Asset retirement obligation		—			2			—			—					—					2
Incomes taxes payable		1			—			—			—					—					1
Risk Management		25			—			—			—					—					25
Current portion of long-term debt		500			—			—			—					—					500

Total Current Liabilities		2,016			807			—			—					90					2,913
Long-Term Debt		3,698			2,436			—			167		c	)		—					6,301
Other Liabilities and Provisions		1,769			66			—			—					—					1,835
Risk Management		22			—			—			—					—					22
Asset Retirement Obligation		365			132			—			25		c	)		—					522
Deferred Income Taxes		27			100			—			(100	)	c	)		—					27

Total Liabilities		7,897			3,541			—			92					90					11,620
Shareholders’ Equity
Share capital		4,656			2			—			(2	)	g	)		3,478		f	)		8,134
Treasury stock		—			(72	)		—			72		g	)		—					—
Paid in surplus		1,358			3,369			—			(3,369	)	g	)		—					1,358
Retained earnings (Accumulated deficit)		435			(1,018	)		—			1,018		g	)		(90	)	e	)		345
Accumulated other comprehensive income		998			(4	)		—			4		g	)		—					998

Total Shareholders’ Equity		7,447			2,277			—			(2,277	)				3,388					10,835

Total Liabilities and Shareholders’ Equity		15,344			5,818			—			(2,185	)				3,478					22,455


	Unaudited Pro Forma Condensed Combined Statement of Earnings
	For the Year Ended December 31, 2018
							Pro Forma Adjustments
($ millions, except per share amounts)	Encana Historical			Newfield Historical			Reclassification Adjustments (Note 3a)			Pro Forma Adjustments (Note 3)					Pro Forma Combined
Revenues
Product and service revenues		5,457			2,630			—			—					8,087
Gains (losses) on risk management, net		415			—			(101	)		—					314
Sublease revenues		67			—			—			—					67
Other revenues		—			13			—			—					13

Total Revenues		5,939			2,643			(101	)							8,481
Operating Expenses
Production, mineral and other taxes		147			125			—			—					272
Transportation and processing		1,083			348			—			—					1,431
Operating		454			269			—			—					723
Purchased product		1,100			—			—			—					1,100
Depreciation, depletion and amortization		1,272			628			(8	)		139		b	)		2,031
Accretion of asset retirement obligation		32			—			8			—					40
Administrative		157			231			—			—					388
Other expenses (income)		—			12			—			—					12

Total Operating Expenses		4,245			1,613			—			139					5,997

Operating Income		1,694			1,030			(101	)		(139	)				2,484
Other (Income) Expenses
Interest		351			151			(59	)		(32	)	c	)		411
Foreign exchange (gain) loss, net		168			—			—			—					168
(Gain) loss on divestitures, net		(5	)		—			—			—					(5	)
Capitalized interest		—			(59	)		59			—					—
Commodity derivative (income) expense		—			101			(101	)		—					—
Other (gains) losses, net		17			(4	)		—			—					13

Total Other (Income) Expenses		531			189			(101	)		(32	)				587

Net Earnings Before Income Tax		1,163			841			—			(107	)				1,897
Income tax expense (recovery)		94			24			—			—		d	)		118

Net Earnings		1,069			817			—			(107	)				1,779

Net Earnings Per Common Share
Basic		1.11														1.18
Diluted		1.11														1.18
Weighted Average Common Shares Outstanding (millions)
Basic		959.8									543.4		e	)		1,503.2
Diluted		959.8									543.4		e	)		1,503.2

NOTES TO UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL STATEMENTS

Note 1 — Basis of Presentation

On February 13, 2019, Encana completed its previously announced business combination with Newfield, pursuant to an Agreement and Plan of Merger (the “merger agreement”), dated as of October 31, 2018, by and among Encana, Neapolitan Merger Corp., a Delaware corporation and an indirect, wholly-owned subsidiary of Encana (“Merger Sub”), and Newfield. Pursuant to the merger agreement, Merger Sub merged with and into Newfield, with Newfield surviving the merger as an indirect, wholly-owned subsidiary of Encana (the “merger”). Under the merger agreement, Newfield stockholders received 2.6719 Encana common shares for each share of Newfield common stock that are issued and outstanding immediately prior to the effective time of the merger.

The unaudited pro forma combined financial information has been derived from the historical consolidated financial statements of Encana and Newfield. Certain of Newfield’s historical amounts have been reclassified to conform to Encana’s financial statement presentation. The unaudited pro forma condensed combined balance sheets as of December 31, 2018 give effect to the merger and the related financing transactions as if they had occurred on December 31, 2018. The unaudited pro forma combined statements of earnings for the year ended December 31, 2018 give effect to the merger and the related financing transactions as if they had occurred on January 1, 2018.

The unaudited pro forma condensed combined financial statements reflect pro forma adjustments that are described in the accompanying notes and are based on available information and certain assumptions that Encana believes are reasonable. However, actual results may differ from those reflected in these statements. In Encana’s opinion, all adjustments that are necessary to present fairly the pro forma information have been made. The following unaudited pro forma combined statements do not purport to represent what the financial position or results of operations would have been if the transaction had actually occurred on the dates indicated above, nor are they indicative of Encana’s future financial position or results of operations. No adjustments have been made to the pro forma financial information to reflect costs savings or synergies that may be obtained as a result of the merger of Newfield described herein.

Note 2 — Unaudited Pro Forma Condensed Combined Balance Sheet

The merger will be accounted for using the acquisition method of accounting for business combinations. The allocation of the preliminary estimated purchase price is based upon Encana management’s estimates of and assumptions related to the fair value of assets to be acquired and liabilities to be assumed, using currently available information. Because the unaudited pro forma combined financial information has been prepared based on these preliminary estimates, the final purchase price allocation and the resulting effect on financial position and results of operations may differ significantly from the pro forma amounts.

The preliminary purchase price allocation is subject to change as a result of several factors, including but not limited to changes between the estimated and final fair value of Newfield’s assets acquired and liabilities assumed and the tax basis of Newfield’s assets and liabilities as of February 13, 2019, the effective time of the merger.

The preliminary consideration transferred, fair value of assets acquired and liabilities assumed were calculated as follows:


($ millions)
Consideration
Fair value of Encana common shares to be issued ⁽¹⁾⁽²⁾			3,478
Fair value of Newfield liability awards paid in cash ⁽³⁾			5

Total Consideration			3,483
Fair Value of Liabilities Assumed
Accounts payable and accrued liabilities			805
Long-Term Debt			2,603
Asset retirement obligations			159
Other non-current liabilities			66
Deferred income tax			225
Fair Value of Assets Acquired
Cash and cash equivalents			292
Accounts receivable and accrued revenues			384
Derivative assets			12
Other current assets			61
Proved property			5,686
Unproved property			746
Other property plant and equipment			54
Other non-current assets			93
Goodwill			13

Net Assets Acquired and Liabilities Assumed			3,483

(1)	Based on 543.4 million Encana common shares at $6.40 per share (closing price as of February 13, 2019 on the NYSE).

(2)

On February 13, 2019, all outstanding Newfield equity awards, including restricted stock awards, restricted stock units and performance share units were cancelled and converted into a right to receive, on a fully vested basis, 2.6719 Encana common shares for each share of restricted stock, each such restricted stock unit and each performance share unit (with the performance-based vesting conditions applicable to such performance share unit deemed achieved based on the determination of the compensation and management development committee of the Newfield board of directors, not to exceed 200%).

(3)

Based on 0.8 million notional Encana common shares at $6.50 per notional unit which was determined using a volume weighted average of the trading price of Encana common shares on each of the five consecutive trading days ending on the trading day that was three trading days prior to February 13, 2019. Newfield liability awards include cash-settled restricted stock units and notional stock under Newfield’s non-qualified deferred compensation plan.

Under the merger agreement, Newfield stockholders received 2.6719 Encana common shares for each share of Newfield common stock issued and outstanding immediately prior to the effective time of the merger. This resulted in Encana issuing approximately 543.4 million of its common shares as merger consideration, or $3.5 billion in value, and cash payments related to the liability awards of approximately $5 million. Based on the NYSE closing price of the Encana common shares of $6.40 on February 13, 2019, the transaction has a value of approximately $6.1 billion, including the fair value of Newfield’s long-term debt assumed of $2.6 billion.

Goodwill recognized is primarily attributable to the excess of the consideration transferred over the acquisition-date identifiable assets acquired net of liabilities assumed, measured in accordance with U.S. GAAP. Newfield’s tax basis in the assets and liabilities will carry over to Encana.

The following adjustments have been made to the accompanying unaudited pro forma combined balance sheet as of December 31, 2018:

(a)	Reflects reclassification of Newfield amounts presented to conform to Encana’s presentation:

•

Pipeline and well equipment from inventory to capital spares in other property plant and equipment;

•

Inventory to accounts receivables and accrued revenues

•

Income tax receivables from other current assets;

•

Gathering assets from other property plant and equipment to proved property;

•

Investments to other long-term assets; and

•

Accrued liabilities and advances from joint owners to accounts payable and accrued liabilities.

(b)

Reflects cash paid in respect of liability awards that were valued at $6.50 per notional unit outstanding, which was determined using a volume weighted average of the trading price of Encana common shares on each of the five consecutive trading days ending on the trading day that is three trading days prior to February 13, 2019.

(c)	The estimated fair value of the assets acquired and liabilities assumed resulted in the following purchase price allocation adjustments:

•

$1.5 billion increase in Newfield’s net book basis of oil and gas properties and other property plant and equipment to reflect them at fair value;

•

$167 million increase to long-term debt to reflect them at fair value and to eliminate debt issuance costs;

•

$25 million increase in asset retirement obligations to reflect them at fair value;

•

$225 million net deferred tax liability associated with the preliminary purchase price allocation; and

•

$13 million increase in goodwill associated with the difference between the fair value of the assets acquired and liabilities assumed and Newfield’s tax basis in the assets and liabilities that will carry over to Encana.

(d)	Reflects the elimination of $11 million in other assets related to Newfield’s credit facility issuance costs.

(e)

Reflects the impact of estimated severance costs of $20 million related to Newfield’s named executive officers as well as transaction costs of $70 million expected to be incurred by Encana and Newfield in connection with the merger, including estimated financial advisor, legal and accounting fees that are not capitalizable as part of the transaction. These costs are not reflected in the historical December 31, 2018 balance sheets of Encana or Newfield but are reflected in the unaudited pro forma balance sheet as an increase to liabilities and a reduction of equity as they will be expensed by Encana and Newfield as incurred. These amounts and their corresponding tax effect have not been reflected in the pro forma statement of earnings due to their non-recurring nature.

(f)	Reflects the increase in Encana’s common shares, with no par value, resulting from the issuance of Encana common shares to Newfield stockholders to effect the transaction as follows (in millions, except share and per share amounts):


Encana common shares issued		543.4
NYSE closing price per share of Encana common shares on February 13, 2019	$	6.40
Fair value of Encana common shares issued		3,478

(g)	Reflects the elimination of Newfield’s historical equity balances in accordance with the acquisition method of accounting.

Note 3. Adjustments to the Unaudited Pro Forma Combined Statements of Earnings

The following adjustments have been made to the accompanying unaudited pro forma combined statements of earnings for the year ended December 31, 2018:

(a)	Reflects reclassification of Newfield amounts presented to conform to Encana’s presentation:

•

Realized and unrealized gains and losses on derivative contracts to be presented in product and service revenues;

•

Capitalized interest included in interest expense; and

•

Accretion from DD&A to accretion of asset retirement obligation.

(b)	Reflects the DD&A expense calculated using Encana’s depletion rate calculated under the full cost method of accounting for oil and gas properties based on the preliminary purchase price allocation.

(c)	Reflects effective interest from the fair valuation of Newfield’s long-term debt using market interest rates.

(d)	Reflects the approximate income tax effects of the pro forma adjustments presented.

(e)	Reflects Encana’s common shares issued to Newfield stockholders.

Exhibit 99.4

SUPPLEMENTAL PRO FORMA OIL, NATURAL GAS LIQUIDS AND NATURAL GAS RESERVES

INFORMATION AS OF DECEMBER 31, 2018

The following tables present the estimated pro forma combined net proved developed and undeveloped, oil, natural gas liquids and natural gas reserves as of December 31, 2018, along with a summary of changes in quantities of net remaining proved reserves during the year ended December 31, 2018. The pro forma reserve information set forth below gives effect to the merger as if the transaction had occurred on January 1, 2018.

The following estimates of the net proved oil and natural gas reserves of Encana’s oil and gas properties as of December 31, 2018 are based on evaluations prepared by Encana’s internal qualified reserves evaluators. In 2018, McDaniel & Associates Consultants Ltd. audited 23% of Encana’s estimated Canadian proved reserve volumes and Netherland, Sewell & Associates, Inc. audited 54% of Encana’s estimated U.S. proved reserve volumes. The following estimates of the net proved oil and natural gas reserves of Newfield’s oil and gas properties are as of December 31, 2018 and were prepared by Newfield’s petroleum engineering staff. Ryder Scott Company and DeGolyer and MacNaughton performed audits of the internally prepared reserve estimates on certain fields aggregating to 97% of 2018 year-end reported proved reserve volumes on a barrel of oil equivalent basis. All reserves information presented herein was prepared in accordance with applicable SEC regulations.

There are numerous uncertainties inherent in estimating quantities and values of proved reserves and in projecting future rates of production and the amount and timing of development expenditures, including many factors beyond the property owner’s control. The following reserve data represents estimates only and should not be construed as being precise. The assumptions used in preparing these estimates may not be realized, causing the quantities of oil and gas that are ultimately recovered, the timing of the recovery of oil and gas reserves, the production and operating costs incurred and the amount and timing of future development expenditures to vary from the estimates presented herein. Actual production, revenues and expenditures with respect to reserves will vary from estimates and the variances may be material.

These estimates were calculated using the 12-month average of the first day of the month reference prices as adjusted for location and quality differentials. Any significant price changes will have a material effect on the quantity and present value of the reserves. These estimates depend on a number of variable factors and assumptions, including historical production from the area compared with production from other comparable producing areas, the assumed effects of regulations by governmental agencies, assumptions concerning future oil and gas prices, and assumptions concerning future operating costs, transportation costs, severance and excise taxes, development costs and workover and remedial costs.

The following estimated pro forma combined net proved developed and undeveloped oil, natural gas liquids and natural gas reserves is not necessarily indicative of the results that might have occurred had the merger been completed on January 1, 2018 and is not intended to be a projection of future results. As a result, future results may vary significantly from the pro form results reflected herein.


	Oil (MMbbls) ⁽²⁾
	Encana Historical Canada			Encana Historical U.S.			Newfield Historical U.S.			Pro Forma Combined U.S.			Newfield Historical China ⁽¹⁾			Pro Forma Combined Total
Balance—December 31, 2017		0.2			192.3			248.0			440.3			2.0			442.5
Revisions and improved recovery		0.2			19.5			(5.0	)		14.5			1.0			15.7
Extensions and discoveries		—			162.4			50.0			212.4			—			212.4
Purchases of reserves in place		—			21.3			1.0			22.3			—			22.3
Sale of reserves in place		—			(11.4	)		(3.0	)		(14.4	)		—			(14.4	)
Production		(0.1	)		(32.7	)		(26.0	)		(58.7	)		(2.0	)		(60.8	)

Balance—December 31, 2018		0.2			351.5			265.0			616.5			1.0			617.7

Proved developed reserves as of
December 31, 2017		0.2			104.7			136.0			240.7			2.0			242.9
December 31, 2018		0.2			150.6			148.0			298.6			1.0			299.8
Proved undeveloped reserves as of
December 31, 2017		—			87.7			112.0			199.7			—			199.7
December 31, 2018		—			200.9			117.0			317.9			—			317.9

	Natural Gas Liquids (MMbbls) ⁽²⁾
	Encana Historical Canada			Encana Historical U.S.			Newfield Historical U.S.			Pro Forma Combined U.S.			Newfield Historical China			Pro Forma Combined Total
Balance—December 31, 2017		115.0			67.5			146.0			213.5			—			328.5
Revisions and improved recovery		(17.4	)		14.2			44.0			58.2			—			40.8
Extensions and discoveries		78.9			48.6			17.0			65.6			—			144.5
Purchases of reserves in place		—			7.7			—			7.7			—			7.7
Sale of reserves in place		—			(5.1	)		—			(5.1	)		—			(5.1	)
Production		(18.0	)		(10.6	)		(16.0	)		(26.6	)		—			(44.6	)

Balance—December 31, 2018		158.5			122.3			191.0			313.3			—			471.8

Proved developed reserves as of
December 31, 2017		40.5			41.6			78.0			119.6			—			160.1
December 31, 2018		60.8			59.4			108.0			167.4			—			228.2
Proved undeveloped reserves as of
December 31, 2017		74.5			25.8			68.0			93.8			—			168.3
December 31, 2018		97.8			62.8			83.0			145.8			—			243.6


	Natural Gas (Bcf) ⁽²⁾
	Encana Historical Canada			Encana Historical U.S.			Newfield Historical U.S.			Pro Forma Combined U.S.			Newfield Historical China		Pro Forma Combined Total
Balance—December 31, 2017		2,135			384			1,704			2,088			—		4,223
Revisions and improved recovery		249			37			211			248			—		497
Extensions and discoveries		885			233			190			423			—		1,308
Purchases of reserves in place		—			39			1			40			—		40
Sale of reserves in place		—			(40	)		(6	)		(46	)		—		(46	)
Production		(368	)		(55	)		(165	)		(220	)		—		(588	)

Balance—December 31, 2018		2,901			598			1,935			2,533			—		5,434

Proved developed reserves as of
December 31, 2017		1,082			243			1,099			1,342			—		2,424
December 31, 2018		1,707			295			1,262			1,557			—		3,264
Proved undeveloped reserves as of
December 31, 2017		1,053			141			605			746			—		1,799
December 31, 2018		1,195			302			673			975			—		2,170

(1)	All of Newfield’s reserves in China are associated with production sharing contracts and are calculated using the economic interest method.

(2)	Numbers may not add due to rounding.

The pro forma standardized measure of discounted future net cash flows relating to proved oil, natural gas liquids and natural gas reserves as of December 31, 2018 is as follows:


($ millions)	Encana Historical Canada		Encana Historical U.S.		Newfield Historical U.S.		Pro Forma Combined U.S.		Newfield Historical China		Pro Forma Combined Total
Future cash inflows		12,463		26,305		26,132		52,437		105		65,005
Less future:
Production costs		5,231		6,399		10,552		16,951		49		22,231
Development costs		2,641		4,751		3,870		8,621		13		11,275
Income taxes		586		1,673		1,653		3,326		—		3,912

Future net cash flows		4,005		13,482		10,057		23,539		43		27,587
Less 10% annual discount for estimated timing of cash flows		1,351		6,532		4,646		11,178		3		12,532

Discounted future net cash flows		2,654		6,950		5,411		12,361		40		15,055

The changes in the pro forma standardized measure of discounted future net cash flows relating to proved oil, natural gas liquids and natural gas reserves for the year ended December 31, 2018 are as follows:


($ millions)	Encana Historical Canada			Encana Historical U.S.			Newfield Historical U.S.			Pro Forma Combined U.S.			Newfield Historical China			Pro Forma Combined Total
Balance, beginning of year—January 1, 2018		1,582			2,731			4,354			7,085			47			8,714
Changes resulting from:
Sales of oil and gas produced during the year		(859	)		(1,753	)		(1,810	)		(3,563	)		(78	)		(4,500	)
Discoveries and extensions, net of related costs		1,130			3,300			879			4,179			—			5,309
Purchases of proved reserves in place		—			468			15			483			—			483
Sales and transfers of proved reserves in place		—			(202	)		(31	)		(233	)		—			(233	)
Net change in prices and production costs		407			1,642			665			2,307			30			2,744
Revisions to quantity estimates		121			526			764			1,290			28			1,439
Accretion of discount		164			273			469			742			3			909
Development costs incurred during the period		665			1,315			777			2,092			1			2,758
Changes in estimated future development costs		(303	)		(824	)		(634	)		(1,458	)		3			(1,758	)
Other		15			16			330			346			6			367
Net change in income taxes		(268	)		(542	)		(367	)		(909	)		—			(1,177	)

Balance, end of year—December 31, 2018		2,654			6,950			5,411			12,361			40			15,055

Exhibit 99.5

REPORT OF RYDER SCOTT COMPANY, L.P.

ENCANA CORPORATION

Estimated

Future Reserves

Attributable to Certain

Leasehold and Royalty Interests

and Derived Through Certain Production Sharing Contracts

SEC Parameters

As of

December 31, 2018


		/s/ Stephen E. Gardner, P.E.
		Stephen E. Gardner, P.E.
		Colorado License No. 44720
		Managing Senior Vice President

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS



TBPE REGISTERED ENGINEERING FIRM F-1580		FAX (303) 623-4258
621 SEVENTEENTH STREET SUITE 1550	DENVER, COLORADO 80293	TELEPHONE (303) 623-9147

February 22, 2019

Encana Corporation

500 Centre Street SE

Calgary, AB

T2G 1A6

Ladies and Gentlemen:

At the request of Encana Corporation (Encana), Ryder Scott Company, L.P. (Ryder Scott) has conducted a reserves audit of the estimates of the proved reserves as of December 31, 2018 prepared by Newfield Exploration Company’s (Newfield) engineering and geological staff based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our reserves audit, completed on February 22, 2019 and presented herein, was prepared for public disclosure by Encana in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations. The estimated reserves shown herein represent Newfield’s estimated net reserves attributable to the leasehold and royalty interests and derived through certain production sharing contracts in certain properties owned by Newfield and which have been acquired by Encana, and the portion of those reserves reviewed by Ryder Scott, as of December 31, 2018. The properties reviewed by Ryder Scott incorporate Newfield’s reserves determinations and are located in the states of Montana, North Dakota, and Utah (Western Region); and offshore in the South China Sea (International Region).

The properties reviewed by Ryder Scott account for a portion of Newfield’s total net proved reserves as of December 31, 2018, which have all been acquired by Encana. Based on the estimates of total net proved reserves prepared by Newfield for the Western and International Regions, the reserves audit conducted by Ryder Scott addresses 35 percent of the total proved developed net liquid hydrocarbon reserves, 8 percent of the total proved developed net gas reserves, 23 percent of the total proved undeveloped net liquid hydrocarbon reserves, and 10 percent of the total proved undeveloped net gas reserves of Newfield. On a barrel of oil equivalency basis, where 6,000 cubic feet of natural gas equal one barrel of oil equivalent, the properties reviewed by Ryder Scott represent 21 percent of the total proved reserves of Newfield, or on a regional basis, 93 percent of Newfield’s Western Region total net proved reserves and 100 percent of Newfield’s International Region total net proved reserves.

As prescribed by the Society of Petroleum Engineers in Paragraph 2.2(f) of the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (SPE auditing standards), a reserves audit is defined as “the process of reviewing certain of the pertinent facts interpreted and assumptions made that have resulted in an estimate of reserves and/or Reserves Information prepared by others and the rendering of an opinion about (1) the appropriateness of the methodologies employed; (2) the adequacy and quality of the data relied upon; (3) the depth and thoroughness of the reserves estimation process; (4) the classification of reserves appropriate to the relevant definitions used; and (5) the reasonableness of the estimated reserve quantities and/or Reserves Information.” Reserves Information may consist of various estimates pertaining to the extent and value of petroleum properties.


1100 LOUISIANA, SUITE 4600	HOUSTON, TEXAS 77002-5294	TEL (713) 651-9191	FAX (713) 651-0849
SUITE 800, 350 7TH AVENUE, S.W.	CALGARY, ALBERTA T2P 3N9	TEL (403) 262-2799	FAX (403) 262-2790

Encana Corporation

February 22, 2019

Page 2

Based on our review, including the data, technical processes and interpretations presented by Newfield, it is our opinion that the overall procedures and methodologies utilized by Newfield in preparing their estimates of the proved reserves as of December 31, 2018 comply with the current SEC regulations and that the overall proved reserves for the reviewed properties as estimated by Newfield are, in the aggregate, reasonable within the established audit tolerance guidelines of 10 percent as set forth in the SPE auditing standards. In calculating whether the net remaining reserves were within tolerance, an equivalent unit basis was used wherein natural gas was converted to oil equivalent using a factor of 6,000 cubic feet per barrel.

The estimated reserves presented in this report are related to hydrocarbon prices. Newfield has informed us that in the preparation of their reserves and income projections, as of December 31, 2018, they used average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations. Actual future prices may vary considerably from the prices required by SEC regulations. The recoverable reserves volumes and the income attributable thereto have a direct relationship to the hydrocarbon prices actually received; therefore, volumes of reserves actually recovered and amounts of income actually received may differ significantly from the estimated quantities presented in this report. The net reserves as estimated by Newfield attributable to Newfield’s interest and entitlement in properties that we reviewed and for those that we did not review are summarized below:

SEC PARAMETERS

Estimated Net Reserves

Certain Leasehold and Royalty Interests and

Derived Through Certain Production Sharing Contracts of

Newfield Exploration Company

As of December 31, 2018


	Proved
	Developed						Total
	Producing		Non-Producing		Undeveloped		Proved
*Audited by Ryder Scott* *Net Reserves*
Oil/Condensate – MBarrels		77,067		1,610		42,326		121,003
Plant Products – MBarrels		10,067		1		4,651		14,719
Gas – MMCF		100,293		2,351		69,201		171,845
*Not Audited by Ryder Scott* *Net Reserves*
Oil/Condensate – MBarrels		67,551		2,375		74,930		144,856
Plant Products – MBarrels		96,331		1,738		78,494		176,563
Gas – MMCF		1,145,976		13,432		603,393		1,762,801
*Total Net Reserves*
Oil/Condensate – MBarrels		144,618		3,985		117,256		265,859
Plant Products – MBarrels		106,398		1,739		83,145		191,282
Gas – MMCF		1,246,269		15,783		672,594		1,934,646

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Encana Corporation

February 22, 2019

Page 3

Liquid hydrocarbons are expressed in standard 42 U.S. gallon barrels and shown herein as thousands of barrels (MBarrels). All gas volumes are reported on an “as sold basis” expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located.

Reserves Included in This Report

In our opinion, the proved reserves presented in this report conform to the definition as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “PETROLEUM RESERVES DEFINITIONS” is included as an attachment to this report.

The various proved reserves status categories are defined under the attachment entitled “PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES” in this report. The proved developed non-producing reserves included herein consist of the shut-in and behind pipe categories.

Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.” All reserves estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At Newfield’s request, this report addresses only the proved reserves attributable to the properties reviewed herein.

Proved oil and gas reserves are “those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward.” The proved reserves included herein were estimated using deterministic methods. The SEC has defined reasonable certainty for proved reserves, when based on deterministic methods, as a “high degree of confidence that the quantities will be recovered.”

Proved reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, could be more or less than the estimated amounts.

Audit Data, Methodology, Procedure and Assumptions

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Encana Corporation

February 22, 2019

Page 4

set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy. These methods may be used individually or in combination by the reserves evaluator in the process of estimating the quantities of reserves. Reserves evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated and the stage of development or producing maturity of the property.

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserves quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserves category assigned by the evaluator. Therefore, it is the categorization of reserves quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely than not to be achieved.” The SEC states that “probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserves category must meet the SEC definitions as noted above.

Estimates of reserves quantities and their associated reserves categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserves categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.

The proved reserves, prepared by Newfield, for the properties that we reviewed were estimated by performance methods, analogy, or a combination of methods. All of the proved producing reserves attributable to producing wells and/or reservoirs that we reviewed were estimated by performance methods or analogy. These performance methods include, but may not be limited to, decline curve analysis which utilized extrapolations of historical production and pressure data ending over a range from August through November 2018, depending on the availability for a given case and in those cases where such data were considered to be definitive. In certain early-life cases, estimates of proved producing reserves were guided by analogy to the decline trends of older, more established wells. The data utilized in this analysis were furnished to Ryder Scott by Newfield or obtained from public data sources and were considered sufficient for the purpose thereof.

The proved developed non-producing reserves that we reviewed were estimated based on historical performance trends before the wells were shut-in or by analogy for the cases that are categorized as behind pipe. The proved undeveloped reserves that we reviewed were estimated by analogy. The data utilized from the analogues were provided to Ryder Scott by Newfield or were obtained by us from public data sources that were available through August to December 2018, depending on the case. The data utilized from the shut-in wells and from the analogues and incorporated into our analysis were considered sufficient for the purpose thereof.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Encana Corporation

February 22, 2019

Page 5

To estimate economically recoverable proved oil and gas reserves, many factors and assumptions are considered including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in conducting this review.

As stated previously, proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. To confirm that the proved reserves reviewed by us meet the SEC requirements to be economically producible, we have reviewed certain primary economic data utilized by Newfield relating to hydrocarbon prices and costs as noted herein.

The hydrocarbon prices furnished by Newfield for the properties reviewed by us are based on SEC price parameters using the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements. For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations exclusive of inflation adjustments, were used until expiration of the contract. Upon contract expiration, the prices were adjusted to the 12-month unweighted arithmetic average as previously described.

The initial SEC hydrocarbon prices in effect on December 31, 2018 for the properties reviewed by us were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used by Newfield for the geographic areas reviewed by us. In certain geographic areas, the price reference and benchmark prices may be defined by contractual arrangements.

The product prices which were actually used by Newfield to determine the future gross revenue for each property reviewed by us reflect adjustments to the benchmark prices for gravity, quality, local conditions, certain handling and processing fees, certain transportation costs, and/or distance from market, referred to herein as “differentials.” The differentials used by Newfield were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Newfield.

The table below summarizes Newfield’s net volume weighted benchmark prices adjusted for differentials for the properties reviewed by us and referred to herein as Newfield’s “average realized prices.” The average realized prices shown in the table below were determined from Newfield’s estimate of the total future gross revenue before production taxes for the properties reviewed by us and Newfield’s estimate of the total net reserves for the properties reviewed by us for each of the geographic areas. The data shown in the table below is presented in accordance with SEC disclosure requirements for each of the geographic areas reviewed by us.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Encana Corporation

February 22, 2019

Page 6

Geographic Area

Product

Price
Reference

Average
Benchmark
Prices

Average
Realized
Prices

North America

Oil/Condensate

WTI Cushing

65.57/Bbl

56.64/Bbl

United States

NGLs

Mont Belvieu Propane

37.58/Bbl

35.91/Bbl

Gas

Henry Hub

3.10/MMBTU

2.78/MCF

Asia

South China Sea

Oil

WTI Cushing

65.57/Bbl

71.43/Bbl

The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in Newfield’s individual property evaluations.

Accumulated gas production imbalances, if any, were not taken into account in the proved gas reserves estimates reviewed. The proved gas volumes presented herein include volumes of gas consumed in operations as reserves. These volumes have been offset with gas price reductions equivalent to the value of the consumed gas.

Operating costs for the leases and wells in this report were provided by Newfield and were represented to be based on their operating expense reports and to include only those costs directly applicable to the leases or wells for the properties reviewed by us. The operating costs include a portion of general and administrative costs allocated directly to the leases and wells. For operated properties, the operating costs include an appropriate level of corporate general administrative and overhead costs. The operating costs for non-operated properties include the COPAS overhead costs that are allocated directly to the leases and wells under terms of operating agreements. In the case of the international properties located offshore in the South China Sea, the cost recoverable expense and investment amounts have been deducted according to the terms of the Production Sharing Contracts. Furthermore, certain Windfall Profits Levy and Export Duty costs are included as Operating Cost deductions. For various U.S. properties, certain transportation, processing and handling fees which are separate for those mentioned above as price differentials are included as “Other” deductions. The operating costs provided to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Newfield. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.

Development costs furnished by Newfield are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished by Newfield were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Newfield. The estimated net cost of abandonment after salvage was included by Newfield for properties where abandonment costs net of salvage were significant. Newfield’s estimates of the net abandonment costs were accepted without independent verification.

The proved developed non-producing and undeveloped reserves for the properties reviewed by us have been incorporated herein in accordance with Newfield’s plans to develop these reserves as of December 31, 2018. The implementation of Newfield’s development plans as presented to us is subject to the approval process adopted by Newfield’s, and now Encana’s, management. As the result of our inquiries during the course of our review, Newfield and Encana have informed us that the development activities for the properties reviewed by us have been subjected to and received the internal approvals

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Encana Corporation

February 22, 2019

Page 7

required by both management teams at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to Newfield and Encana. Additionally, Newfield and Encana have informed us that they are not aware of any legal, regulatory, or political obstacles that would significantly alter their plans. While these plans could change from those under existing economic conditions as of December 31, 2018, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

Current costs used by Newfield were held constant throughout the life of the properties.

Newfield’s forecasts of future production rates are based on historical performance from wells currently on production. If no production decline trend has been established, future production rates were based on the decline trends of analogous wells. If a decline trend has been established, this trend was used as the basis for estimating future production rates.

Test data, analogy data and other related information were used by Newfield to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by Newfield. Wells or locations that are not currently producing may start producing earlier or later than anticipated in Newfield’s estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, well completions, and/or constraints set by regulatory bodies.

Certain proved reserves associated with Newfield’s international assets reported herein are limited to the period prior to expiration of current contracts providing the legal right to produce or a revenue interest in such production, unless evidence indicates that contract renewal is reasonably certain. Furthermore, properties in different countries may be subjected to significantly varying contractual fiscal terms that affect the net revenue to Newfield, or Encana following its acquisition of Newfield, for the production of these volumes. The prices and economic return received for these net volumes can vary significantly based on the terms of these contracts. Therefore, when applicable, Ryder Scott reviewed the fiscal terms of such contracts and discussed with Newfield the net economic benefit attributed to such operations for the determination of the net hydrocarbon volumes and income thereof. Ryder Scott has not conducted an exhaustive audit or verification of such contractual information. Neither our review of such contractual information nor our acceptance of Newfield’s representations regarding such contractual information should be construed as a legal opinion on this matter.

Ryder Scott did not evaluate the country and geopolitical risks in the countries where Newfield operates or has interests. Newfield’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons including the granting, extension or termination of production sharing contracts, the fiscal terms of various production sharing contracts, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax, and foreign trade and investment and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.

The estimates of proved reserves presented herein were based upon a review of the properties in which Newfield owns and derives an interest, and which have been acquired by Encana; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included by Newfield for potential liabilities to restore and clean up damages, if any, caused by past operating practices.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Encana Corporation

February 22, 2019

Page 8

Certain technical personnel of Newfield are responsible for the preparation of reserve estimates on new properties and for the preparation of revised estimates, when necessary, on old properties. These personnel assembled the necessary data and maintained the data and workpapers in an orderly manner. We consulted with these technical personnel and had access to their workpapers and supporting data in the course of our audit.

Newfield has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In performing our audit of Newfield’s forecast of future proved production, we have relied upon data furnished by Newfield with respect to property interests owned or derived, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, ad valorem and production taxes, Production Sharing Contract terms, development costs, development plans, abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and isochore maps, well logs, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by Newfield. We consider the factual data furnished to us by Newfield to be appropriate and sufficient for the purpose of our review of Newfield’s estimates of reserves and future net income. In summary, we consider the assumptions, data, methods and analytical procedures used by Newfield and as reviewed by us appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate under the circumstances to render the conclusions set forth herein.

Audit Opinion

Based on our review, including the data, technical processes and interpretations presented by Newfield, it is our opinion that the overall procedures and methodologies utilized by Newfield in preparing their estimates of the proved reserves as of December 31, 2018 comply with the current SEC regulations and that the overall proved reserves for the reviewed properties as estimated by Newfield are, in the aggregate, reasonable within the established audit tolerance guidelines of 10 percent as set forth in the SPE auditing standards. Ryder Scott found the processes and controls used by Newfield in their estimation of proved reserves to be effective and, in the aggregate, we found no bias in the utilization and analysis of data in estimates for these properties.

We were in reasonable agreement with Newfield’s estimates of proved reserves for the properties which we reviewed; although in certain cases there was more than an acceptable variance between Newfield’s estimates and our estimates due to a difference in interpretation of data or due to our having access to data which were not available to Newfield when its reserve estimates were prepared. However notwithstanding, it is our opinion that on an aggregate basis the data presented herein for the properties that we reviewed fairly reflects the estimated net reserves owned by Newfield, which have been acquired by Encana.

Other Properties

Other properties, as used herein, are those properties of Newfield which we did not review. The proved net reserves attributable to the other properties account for 70 percent of the total proved net liquid hydrocarbon reserves and 91 percent of the total proved net gas reserves based on estimates prepared by Newfield as of December 31, 2018. On a barrel of oil equivalency basis, where 6,000 cubic feet of natural gas equal one barrel of oil equivalent, the other properties represent 79 percent of the total proved reserves of Newfield.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Encana Corporation

February 22, 2019

Page 9

Standards of Independence and Professional Qualification

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1937. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have approximately eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.

Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.

Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization. Regulating agencies require that, in order to maintain active status, a certain amount of continuing education hours be completed annually, including an hour of ethics training. Ryder Scott fully supports this technical and ethics training with our internal requirement mentioned above.

We are independent petroleum engineers with respect to Newfield and Encana. Neither we nor any of our employees have any financial interest in the subject properties, and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

The results of this audit, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for overseeing, reviewing and approving the review of the reserves information discussed in this report, are included as an attachment to this letter.

Terms of Usage

The results of our third party audit, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by Encana.

Encana makes periodic filings on Form 8-K and annual filings on Form 10-K with the SEC under the 1934 Exchange Act. Furthermore, Encana has certain registration statements filed with the SEC under the 1933 Securities Act into which any subsequently filed Form 8-K and Form 10-K may be

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Encana Corporation

February 22, 2019

Page 10

incorporated by reference. We have consented to the incorporation by reference in the registration statements on Form S-3 (File Nos. 333-216395) and Form S-8 (File Nos. 333-124218, 333-85598, 333-140856 and 333-188758) of Encana, of the references to our name as well as to the references to our third party report, which appears in the current report on Form 8-K of Encana. Our written consent for such use is included as a separate exhibit to the filings made with the SEC by Encana..

We have provided Encana with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by Encana and the original signed report letter, the original signed report letter shall control and supersede the digital version.

The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

Very truly yours,

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

/s/ Stephen E. Gardner, P.E.

Stephen E. Gardner, P.E.

Colorado License No. 44720

Managing Senior Vice President

SEG (XXX)/pl

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Professional Qualifications of Primary Technical Person

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Mr. Stephen E. Gardner is the primary technical person responsible for the estimate of the reserves, future production and income.

Mr. Gardner, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 2006, is a Managing Senior Vice President responsible for ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Gardner served in a number of engineering positions with Exxon Mobil Corporation. For more information regarding Mr. Gardner’s geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com/Experience/Employees.

Mr. Gardner earned a Bachelor of Science degree in Mechanical Engineering from Brigham Young University in 2001 (summa cum laude). He is a licensed Professional Engineer in the States of Colorado and Texas. Mr. Gardner is also a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers, serving in the latter organization’s Denver Chapter as Chairman during 2018.

In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of 15 hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Gardner fulfills. As part of his 2018 continuing education hours, Mr. Gardner attended the annual Ryder Scott Reserves Conference in Houston, Texas which covered a variety of reserves topics including updated PRMS guidelines, data analytics, unconventional resource issues, SEC comment letter trends, and others. In addition, Mr. Gardner attended the 2018 SPEE conference held in Carlsbad, California, various local SPEE technical seminars, and other internal company training courses during the year covering topics such as analysis techniques for unconventional reservoirs, ethics, reserves evaluation, and more.

Based on his educational background, professional training and more than 13 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Gardner has attained the professional qualifications as a Reserves Estimator set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

PREAMBLE

On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”. The SEC regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italics herein).

Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.

Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.

Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

Page 2

Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.

Reserves do not include quantities of petroleum being held in inventory.

Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.

RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:

Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir ( i.e. , absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources ( i.e. , potentially recoverable resources from undiscovered accumulations).

PROVED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:

Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

Page 3

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

and

2018 PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)

Sponsored and Approved by:

SOCIETY OF PETROLEUM ENGINEERS (SPE)

WORLD PETROLEUM COUNCIL (WPC)

AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)

SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)

SOCIETY OF EXPLORATION GEOPHYSICISTS (SEG)

SOCIETY OF PETROPHYSICISTS AND WELL LOG ANALYSTS (SPWLA)

EUROPEAN ASSOCIATION OF GEOSCIENTISTS & ENGINEERS (EAGE)

Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein).

DEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:

Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Developed Producing (SPE-PRMS Definitions)

While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.

Developed Producing Reserves

Developed Producing Reserves are expected quantities to be recovered from completion intervals that are open and producing at the effective date of the estimate.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

Page 2

Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Developed Non-Producing

Developed Non-Producing Reserves include shut-in and behind-pipe Reserves.

Shut-In

Shut-in Reserves are expected to be recovered from:

(1)

completion intervals that are open at the time of the estimate but which have not yet started producing;

(2)

wells which were shut-in for market conditions or pipeline connections; or

(3)

wells not capable of production for mechanical reasons.

Behind-Pipe

Behind-pipe Reserves are expected to be recovered from zones in existing wells that will require additional completion work or future re-completion before start of production with minor cost to access these reserves.

In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

UNDEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:

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

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Exhibit 99.6

REPORT OF DEGOLYER AND MACNAUGHTON

DeGolyer and MacNaughton

5001 Spring Valley Road

Suite 800 East

Dallas, Texas 75244

January 28, 2019

Newfield Exploration Mid-Continent Inc.

4 Waterway Square Place

Suite 100

The Woodlands, Texas 77380

Ladies and Gentlemen:

Pursuant to your request, this report of third party presents an independent evaluation, as of December 31, 2018, of the estimated net proved oil, condensate, natural gas liquids (NGL), and gas reserves of certain properties in which Newfield Exploration Mid-Continent Inc. (Newfield) has represented it holds an interest. This evaluation was completed on January 28, 2019. The properties evaluated consist of working and royalty interests located in Oklahoma. Newfield has represented that these properties account for 98 percent on a net equivalent barrel basis of Newfield’s net proved reserves as of December 31, 2018, and that the net proved reserves estimates have been prepared in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the Securities and Exchange Commission (SEC) of the United States. We have reviewed information provided by Newfield that it represents to be Newfield’s estimates of the net reserves, as of December 31, 2018, for the same properties as those which we evaluated. This report was prepared in accordance with guidelines specified in Item 1202 (a)(8) of Regulation S–K and is to be used for inclusion in certain SEC filings by Newfield.

Reserves estimates included herein are expressed as net reserves as represented by Newfield. Gross reserves are defined as the total estimated petroleum remaining to be produced from these properties after December 31, 2018. Net reserves are defined as that portion of the gross reserves attributable to the interests held by Newfield after deducting all interests held by others.

Estimates of reserves should be regarded only as estimates that may change as production history and additional information become available. Not only are such estimates based on that information which is currently available, but suchestimates are also subject to the uncertainties inherent in the application of judgmental factors in interpreting such information.


DeGolyer and MacNaughton		3

Information used in the preparation of this report was obtained from Newfield and from public sources. Additionally, this information included data supplied by IHS Markit Inc; Copyright 2018 IHS Markit Inc. In the preparation of this report we have relied, without independent verification, upon information furnished by Newfield with respect to the property interests being evaluated, production from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, and various other information and data that were accepted as represented. A field examination of the properties was not considered necessary for the purposes of this report.

Definition of Reserves

Petroleum reserves included in this report are classified as proved. Only proved reserves have been evaluated for this report. Reserves classifications used in this report are in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC. Reserves are judged to be economically producible in future years from known reservoirs under existing economic and operating conditions and assuming continuation of current regulatory practices using conventional production methods and equipment. In the analyses of production-decline curves, reserves were estimated only to the limit of economic rates of production under existing economic and operating conditions using prices and costs consistent with the effective date of this report, including consideration of changes in existing prices provided only by contractual arrangements but not including escalations based upon future conditions. The petroleum reserves are classified as follows:

Proved oil and gas reserves – Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.


DeGolyer and MacNaughton		4

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:


DeGolyer and MacNaughton		5

Developed oil and gas reserves – Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

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

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in [section 210.4–10 (a) Definitions], or by other evidence using reliable technology establishing reasonable certainty.


DeGolyer and MacNaughton		6

Methodology and Procedures

Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principles and techniques that are in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC and with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007)” and in Monograph 3 and Monograph 4 published by the Society of Petroleum Evaluation Engineers. The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, and production history.

Based on the current stage of field development, production performance, the development plans provided by Newfield, and analyses of areas offsetting existing wells with test or production data, reserves were classified as proved.

Newfield has represented that its senior management is committed to the development plan provided by Newfield and that Newfield has the financial capability to execute the development plan, including the drilling and completion of wells and the installation of equipment and facilities.

A performance-based methodology integrating the appropriate geology and petroleum engineering data was utilized for the evaluation of all reserves categories. Performance-based methodology primarily includes (1) production diagnostics,(2) decline-curve analysis, and (3) model-based analysis (if necessary, based on the availability of data). Production diagnostics include data quality control, identification of flow regimes, and characteristic well performance behavior. Analysis was performed for all well groupings (or type-curve areas).

Characteristic rate-decline profiles from diagnostic interpretation were translated to modified hyperbolic rate profiles, including one or multiple b-exponent values followed by an exponential decline. Based on the availability of data, model-based analysis may be integrated to evaluate long-term decline behavior, the impact of dynamic reservoir and fracture parameters on well performance, and complex situations sourced by the nature of unconventional reservoirs. The methodology used for the analysis was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, production history, and appropriate reserves definitions.


DeGolyer and MacNaughton		7

In certain cases, reserves were estimated by incorporating elements of analogy with similar wells or reservoirs for which more complete data were available.

Data provided by Newfield from wells drilled through December 31, 2018, and made available for this evaluation were used to prepare the reserves estimates herein. These reserves estimates were based on consideration of monthly production data available for certain properties only through September 2018. Estimated cumulative production, as of December 31, 2018, was deducted from the estimated gross ultimate recovery to estimate gross reserves. This required that production be estimated for up to 3 months.

Oil and condensate reserves estimated herein are those to be recovered by normal field separation. NGL reserves estimated herein include C ₅₊ and liquefied petroleum gas (LPG), which consists primarily of propane and butane fractions. NGL reserves are the result of low-temperature plant processing. Oil, condensate, and NGL reserves included in this report are expressed in barrels (bbl) representing 42 United States gallons per barrel. For reporting purposes, oil and condensate reserves have been estimated separately and are presented herein as a summed quantity.

Gas quantities estimated herein are expressed as marketable gas. Marketable gas is defined as the sum of sales gas and fuel gas. Sales gas is defined as the total gas to be produced from the reservoirs, measured at the point of delivery, after reduction for fuel use and shrinkage resulting from field separation and processing. Fuel gas is that portion of the total gas to be produced from the reservoirs used in the operation of the fields. Newfield accounts for fuel gas quantities with shrinkage and gas price reductions that are equivalent to the value of the gas quantities consumed in operations and therefore fuel gas cannot be quantified herein. Gas reserves estimated herein are reported as marketable gas. All gas reserves are expressed at a temperature base of 60 degrees Fahrenheit (°F) and at a pressure base of 14.65 pounds per square inch absolute (psia). Gas reserves included in this report are expressed in thousands of cubic feet (Mcf).

Gas quantities are identified by the type of reservoir from which the gas will be produced. Nonassociated gas is gas at initial reservoir conditions with no oil present in the reservoir. Associated gas is both gas-cap gas and solution gas. Gas-cap gas is gas at initial reservoir conditions and is in communication with an underlying oil zone. Solution gas is gas dissolved in oil at initial reservoir conditions. Gas quantities estimated herein include both associated and nonassociated gas.


DeGolyer and MacNaughton		8

At the request of Newfield, marketable gas reserves estimated herein were converted to oil equivalent using an energy equivalent factor of 6,000 cubic feet of gas per 1 barrel of oil equivalent. This conversion factor was provided by Newfield.

Primary Economic Assumptions

This report has been prepared using initial prices, expenses, and costs provided by Newfield. Future prices were estimated using guidelines established by the SEC and the Financial Accounting Standards Board (FASB). The following economic assumptions were used for estimating the reserves reported herein:

Oil, Condensate, and NGL Prices

Newfield has represented that the oil, condensate, and NGL prices were based on West Texas Intermediate (WTI) pricing, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual agreements. The oil, condensate, and NGL prices were calculated using differentials furnished by Newfield to the reference price of $65.57 per barrel and held constant thereafter. The volume-weighted average prices attributable to the estimated proved reserves over the lives of the properties were $66.01 per barrel of oil and condensate and $25.28 per barrel of NGL.

Gas Prices

Newfield has represented that the gas prices were based on Henry Hub pricing, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual agreements. The gas prices were calculated for each property using differentials furnished by Newfield to the reference price of $3.10 per million British thermal units ($/MMBtu) and held constant thereafter. British thermal unit factors provided by Newfield were used to convert prices from $/MMBtu to dollars per thousand cubic feet. The volume-weighted average price attributable to the estimated proved reserves over the lives of the properties was $2.681 per thousand cubic feet of gas.


DeGolyer and MacNaughton		9

Production Taxes

Production taxes were calculated using the tax rates for Oklahoma, including, where appropriate, abatements for enhanced recovery programs.

Operating Expenses, Capital Costs, and Abandonment Costs

Estimates of operating expenses, provided by Newfield and based on current expenses, were held constant for the lives of the properties. Future capital expenditures were estimated using 2018 values, provided by Newfield, and were not adjusted for inflation. In certain cases, future expenditures, either higher or lower than current expenditures, may have been used because of anticipated changes in operating conditions, but no general escalation that might result from inflation was applied. Abandonment costs, which are those costs associated with the removal of equipment, plugging of wells, and reclamation and restoration associated with the abandonment, were provided by Newfield for all properties and were not adjusted for inflation. Operating expenses, capital costs, and abandonment costs were considered, as appropriate, in determining the economic viability of non-producing and undeveloped reserves estimated herein.

In our opinion, the information relating to estimated proved reserves of oil, condensate, natural gas liquids, and gas contained in this report has been prepared in accordance with Paragraphs 932-235-50-4, 932-235-50-6, 932-235-50-7, and 932-235-50-9 of the Accounting Standards Update 932-235-50, Extractive Industries – Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures (January 2010) of the Financial Accounting Standards Board and Rules 4–10(a)(1)–(32) of Regulation S–X and Rules 302(b), 1201, 1202(a) (1), (2), (3), (4), (8), and 1203(a) of Regulation S–K of the Securities and Exchange Commission; provided, however, that estimates of proved developed and proved undeveloped reserves are not presented at the beginning of the year.

To the extent the above-enumerated rules, regulations, and statements require determinations of an accounting or legal nature, we, as engineers, are necessarily unable to express an opinion as to whether the above-described information is in accordance therewith or sufficient therefor.


DeGolyer and MacNaughton		10

Summary of Conclusions

Newfield has represented that its estimated net proved reserves attributable to the evaluated properties were based on the definitions of proved reserves of the SEC. Newfield’s estimates of the net proved reserves attributable to these properties, which represent 98 percent of Newfield’s total proved reserves on a net equivalent basis, are summarized as follows, expressed in thousands of barrels (Mbbl), millions of cubic feet (MMcf), and thousands of barrels of oil equivalent (Mboe):


	Estimated by Newfield Net Proved Reserves as of December 31, 2018
	Oil and Condensate (Mbbl)		NGL (Mbbl)		Marketable Gas (MMcf)		Oil Equivalent (Mboe)
Proved Developed Producing		59,904		94,172		1,081,101		334,259
Proved Developed Non-Producing		2,374		1,737		13,431		6,350

Total Proved Developed		62,278		95,909		1,094,532		340,609
Proved Undeveloped		73,363		76,526		589,825		248,193

Total Proved		135,641		172,435		1,684,357		588,802

Note:

Marketable gas reserves estimated herein were converted to oil equivalent using an energy equivalent factor of 6,000 cubic feet of gas per 1 barrel of oil equivalent.


DeGolyer and MacNaughton		11

In comparing the detailed net proved reserves estimates prepared by DeGolyer and MacNaughton and by Newfield, differences have been found, both positive and negative, resulting in an aggregate difference of less than 10 percent when compared on the basis of net equivalent barrels and is within the established audit tolerance standards established by the SPE “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information.” It is DeGolyer and MacNaughton’s opinion that there is no material difference between the net proved reserves estimates prepared by Newfield and those prepared by DeGolyer and MacNaughton for those properties evaluated herein.

While the oil and gas industry may be subject to regulatory changes from time to time that could affect an industry participant’s ability to recover its reserves, we are not aware of any such governmental actions which would restrict the recovery of the December 31, 2018, estimated reserves.

DeGolyer and MacNaughton is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1936. DeGolyer and MacNaughton does not have any financial interest, including stock ownership, in Newfield. Our fees were not contingent on the results of our evaluation. This report has been prepared at the request of Newfield. DeGolyer and MacNaughton has used all data, assumptions, procedures, and methods that it considers necessary to prepare this report.

Submitted,

/s/ DeGOLYER and MacNAUGHTON

DeGOLYER and MacNAUGHTON

Texas Registered Engineering Firm F-716

/s/ Gregory K. Graves, P.E.

Gregory K. Graves, P.E.

Senior Vice President

DeGolyer and MacNaughton

CERTIFICATE of QUALIFICATION

I, Gregory K. Graves, Petroleum Engineer with DeGolyer and MacNaughton, 5001 Spring Valley Road, Suite 800 East, Dallas, Texas, 75244 U.S.A., hereby certify:

That I am a Senior Vice President with DeGolyer and MacNaughton, which firm did prepare the report of third party addressed to Newfield dated January 28, 2019, and that I, as Senior Vice President, was responsible for the preparation of this report of third party.

That I attended the University of Texas at Austin, and that I graduated with a Bachelor of Science degree in Petroleum Engineering in the year 1984; that I am a Registered Professional Engineer in the State of Texas; that I am a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers; and that I have in excess of 34 years of experience in oil and gas reservoir studies and reserves evaluations.

/s/ Gregory K. Graves, P.E.

Gregory K. Graves, P.E.

Senior Vice President

DeGolyer and MacNaughton