Last10K.com

Devon Energy Corpde (DVN) SEC Filing 10-K Annual report for the fiscal year ending Monday, December 31, 2018

Devon Energy Corpde

CIK: 1090012 Ticker: DVN

Exhibit 99.1

 

LOGO

NEWS RELEASE

Devon Energy Announces Final Step to Complete Transformation to U.S. Oil Growth Company

Highlights

 

   

Pursuing separation of its Canadian and Barnett Shale assets

 

   

Expect to complete separation by end of 2019

 

   

Share-repurchase authorization increased to $5 billion

 

   

Quarterly dividend increased 13 percent

 

   

Committed to at least $780 million in annual cost reductions

OKLAHOMA CITY – Feb. 19, 2019

– Devon Energy Corp. (NYSE: DVN) today announced that the board of directors has authorized the company to pursue the separation of its Canadian and Barnett Shale assets to complete its transformation to a high-return U.S. oil growth business. Devon will evaluate multiple methods of separating the assets, including a potential sale or spin-off. The separation will allow the company to focus on its top-tier, high-return U.S. oil assets and is aligned with Devon’s previously announced long-term strategic plan.

“With our world-class U.S. oil resource plays rapidly building momentum and achieving operating scale, the final step in our multi-year transformation is an aggressive, transformational move that will accelerate value creation for our shareholders by further simplifying our resource-rich asset portfolio,” said Dave Hager, president and CEO. “New Devon will emerge with a highly focused U.S. asset portfolio and has the ability to substantially increase returns and profitability as we aggressively align our cost structure to expand margins with this top-tier oil business. The New Devon will be able to grow oil volumes at a mid-teens rate while generating free cash flow at pricing above $46 per barrel.”

The company expects to complete the separation of its Canadian and Barnett Shale assets by the end of 2019. Devon has hired advisors for each asset, and data rooms for Canada and the Barnett are expected to be open by the second quarter of 2019. The company anticipates using potential proceeds from the separation of these assets to maintain target debt levels of 1.0-to-1.5 times EBITDA and to continue Devon’s industry-leading share repurchase activity.

Share-Repurchase Program Increased to $5 Billion and Dividend Raised 13 Percent

Devon also announced today that its board of directors authorized a $1 billion increase to the company’s previously announced $4 billion share-repurchase program, bringing the total repurchase program to $5 billion. The authorization for the repurchase program expires on Dec. 31, 2019. As of Feb. 18, 2019, Devon had completed $3.4 billion of repurchases under the program, totaling approximately 90 million shares.

All purchases will be made in accordance with applicable laws from time to time in open-market or private transactions, depending on market conditions, and may be discontinued at any time. At the current share price, this program covers nearly 30 percent of the company’s outstanding common stock.

 

1


The following information was filed by Devon Energy Corpde (DVN) on Tuesday, February 19, 2019 as an 8K 2.02 statement, which is an earnings press release pertaining to results of operations and financial condition. It may be helpful to assess the quality of management by comparing the information in the press release to the information in the accompanying 10-K Annual Report statement of earnings and operation as management may choose to highlight particular information in the press release.

Table of Contents

 

Index to Financial Statements

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

Form 10-K

 

(Mark One)

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

For the fiscal year ended December 31, 2018

or

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

Commission File Number 001-32318

 

DEVON ENERGY CORPORATION

(Exact name of registrant as specified in its charter)

 

 

Delaware

 

73-1567067

(State or other jurisdiction of incorporation or organization)

 

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

 

 

333 West Sheridan Avenue, Oklahoma City, Oklahoma

 

73102-5015

(Address of principal executive offices)

 

(Zip code)

Registrant’s telephone number, including area code:

(405) 235-3611

Securities registered pursuant to Section 12(b) of the Act:

 

 

Title of each class

 

Name of each exchange on which registered

 

 

Common stock, par value $0.10 per share

 

The New York Stock Exchange

 

Securities registered pursuant to Section 12(g) of the Act: None

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes       No  

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes      No  

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

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).    Yes      No  

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.    

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

 

Large accelerated filer

 

Accelerated filer

 

Non-accelerated filer

 

Smaller reporting company

 

Emerging growth company

 

 

 

 

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).    Yes      No  

The aggregate market value of the voting common stock held by non-affiliates of the registrant as of June 29, 2018 was approximately $22.5 billion, based upon the closing price of $43.96 per share as reported by the New York Stock Exchange on such date. On February 6, 2019, 438.3 million shares of common stock were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of Registrant’s definitive Proxy Statement relating to Registrant’s 2019 annual meeting of stockholders have been incorporated by reference in Part III of this Annual Report on Form 10-K.

 


Table of Contents

 

Index to Financial Statements

DEVON ENERGY CORPORATION

FORM 10-K

TABLE OF CONTENTS

 

PART I

 

6

 

 

 

Items 1 and 2. Business and Properties

 

6

Item 1A.  Risk Factors

 

14

Item 1B.  Unresolved Staff Comments

 

21

Item 3.     Legal Proceedings

 

21

Item 4.     Mine Safety Disclosures

 

21

 

 

 

PART II

 

22

 

 

 

Item 5.     Market for Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

 

22

Item 6.     Selected Financial Data

 

24

Item 7.     Management’s Discussion and Analysis of Financial Condition and Results of Operations

 

25

Item 7A.  Quantitative and Qualitative Disclosures about Market Risk

 

49

Item 8.     Financial Statements and Supplementary Data

 

50

Item 9.     Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

 

109

Item 9A.  Controls and Procedures

 

109

Item 9B.  Other Information

 

109

 

 

 

PART III

 

110

 

 

 

Item 10.   Directors, Executive Officers and Corporate Governance

 

110

Item 11.   Executive Compensation

 

110

Item 12.   Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

 

110

Item 13.   Certain Relationships and Related Transactions, and Director Independence

 

110

Item 14.   Principal Accountant Fees and Services

 

110

 

 

 

PART IV

 

111

 

 

 

Item 15.   Exhibits and Financial Statement Schedules

 

111

Item 16.   Form 10-K Summary

 

116

Signatures

 

117

 

2


Table of Contents

 

Index to Financial Statements

DEFINITIONS

Unless the context otherwise indicates, references to “us,” “we,” “our,” “ours,” “Devon,” the “Company” and “Registrant” refer to Devon Energy Corporation and its consolidated subsidiaries. All monetary values, other than per unit and per share amounts, are stated in millions of U.S. dollars unless otherwise specified. In addition, the following are other abbreviations and definitions of certain terms used within this Annual Report on Form 10-K:

“2009 Plan” means the Devon Energy Corporation 2009 Long-Term Incentive Plan, as amended and restated.

“2015 Plan” means the Devon Energy Corporation 2015 Long-Term Incentive Plan.

“2017 Plan” means the Devon Energy Corporation 2017 Long-Term Incentive Plan.

“2012 Senior Credit Facility” means Devon’s syndicated unsecured revolving line of credit, effective as of October 24, 2012.

“2018 Senior Credit Facility” means Devon’s syndicated unsecured revolving line of credit, effective as of October 5, 2018.

“ASC” means Accounting Standards Codification.

“ASR” means an accelerated share-repurchase transaction with a financial institution to repurchase Devon’s common stock.

“ASU” means Accounting Standards Update.

“Bbl” or “Bbls” means barrel or barrels.

“Bcf” means billion cubic feet.

“BLM” means the United States Bureau of Land Management.

“Boe” means barrel of oil equivalent. Gas proved reserves and production are converted to Boe, at the pressure and temperature base standard of each respective state in which the gas is produced, at the rate of six Mcf of gas per Bbl of oil, based upon the approximate relative energy content of gas and oil. Bitumen and NGL proved reserves and production are converted to Boe on a one-to-one basis with oil.

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

“Canada” means the division of Devon encompassing oil and gas properties located in Canada. All dollar amounts associated with Canada are in U.S. dollars, unless stated otherwise.

“Canadian Plan” means Devon Canada Corporation Incentive Savings Plan.

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

“Devon Financing” means Devon Financing Company, L.L.C.

“Devon Plan” means Devon Energy Corporation Incentive Savings Plan.

“EnLink” means EnLink Midstream Partners, LP, a master limited partnership.

“EPA” means the United States Environmental Protection Agency.

“FASB” means Financial Accounting Standards Board.

“Federal Funds Rate” means the interest rate at which depository institutions lend balances at the Federal Reserve to other depository institutions overnight.

“G&A” means general and administrative expenses.

“GAAP” means U.S. generally accepted accounting principles.

“General Partner” means EnLink Midstream, LLC, the indirect general partner entity of EnLink, and, unless the context otherwise indicates, EnLink Midstream Manager, LLC, the managing member of EnLink Midstream, LLC.

“Inside FERC” refers to the publication Inside F.E.R.C.’s Gas Market Report.

“LIBOR” means London Interbank Offered Rate.

“LOE” means lease operating expenses.

“MBbls” means thousand barrels.

“MBoe” means thousand Boe.

3


Table of Contents

 

Index to Financial Statements

“Mcf” means thousand cubic feet.

“MMBbls” means million barrels.

“MMBoe” means million Boe.

“MMBtu” means million Btu.

“MMcf” means million cubic feet.

“N/M” means not meaningful.

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

“NYMEX” means New York Mercantile Exchange.

“NYSE” means New York Stock Exchange.

“OPEC” means Organization of the Petroleum Exporting Countries.

“OPIS” means Oil Price Information Service.

“PHMSA” means United States Department of Transportation Pipeline and Hazardous Materials Safety Administration.

“SEC” means United States Securities and Exchange Commission.

“Standardized measure” means the present value of after-tax future net revenues discounted at 10% per annum.

“S&P 500 Index” means Standard and Poor’s 500 index.

“Tax Reform Legislation” means Tax Cuts and Jobs Act.

“TSR” means total shareholder return.

“Upstream operations” means upstream revenues minus production expenses.

“U.S.” means United States of America.

“WTI” means West Texas Intermediate.

“/Bbl” means per barrel.

“/d” means per day.

“/MMBtu” means per MMBtu.

 

 


4


Table of Contents

 

Index to Financial Statements

INFORMATION REGARDING FORWARD-LOOKING STATEMENTS

This report includes “forward-looking statements” as defined by the SEC. Such statements include those concerning strategic plans, our expectations and objectives for future operations, as well as other future events or conditions, and are often identified by use of the words and phrases “expects,” “believes,” “will,” “would,” “could,” “continue,” “may,” “aims,” “likely to be,” “intends,” “forecasts,” “projections,” “estimates,” “plans,” “expectations,” “targets,” “opportunities,” “potential,” “anticipates,” “outlook” and other similar terminology. All statements, other than statements of historical facts, included in this report that address activities, events or developments that Devon expects, believes or anticipates will or may occur in the future are forward-looking statements. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond our control. Consequently, actual future results could differ materially from our expectations due to a number of factors, including, but not limited to:

 

the volatility of oil, gas and NGL prices;

 

uncertainties inherent in estimating oil, gas and NGL reserves;

 

the extent to which we are successful in acquiring and discovering additional reserves;

 

the uncertainties, costs and risks involved in our operations, including as a result of employee misconduct;

 

regulatory restrictions, compliance costs and other risks relating to governmental regulation, including with respect to environmental matters;

 

risks related to regulatory, social and market efforts to address climate change;

 

risks related to our hedging activities;

 

counterparty credit risks;

 

risks relating to our indebtedness;

 

cyberattack risks;

 

our limited control over third parties who operate some of our oil and gas properties;

 

midstream capacity constraints and potential interruptions in production;

 

the extent to which insurance covers any losses we may experience;

 

competition for assets, materials, people and capital;

 

our ability to successfully complete mergers, acquisitions and divestitures; and

 

any of the other risks and uncertainties discussed in this report.

All subsequent written and oral forward-looking statements attributable to Devon, or persons acting on its behalf, are expressly qualified in their entirety by the cautionary statements above. We assume no duty to update or revise our forward-looking statements based on new information, future events or otherwise.

 

5


Table of Contents

 

Index to Financial Statements

PART I

Items 1 and 2. Business and Properties

General

A Delaware corporation formed in 1971 and publicly held since 1988, Devon (NYSE: DVN) is an independent energy company engaged primarily in the exploration, development and production of oil, natural gas and NGLs. Our operations are concentrated in various North American onshore areas in the U.S. and Canada. In July 2018, we exited the midstream business by divesting our aggregate ownership interests in EnLink and the General Partner.

Our principal and administrative offices are located at 333 West Sheridan, Oklahoma City, OK 73102-5015 (telephone 405-235-3611). As of December 31, 2018, Devon and its consolidated subsidiaries had approximately 2,900 employees.

Devon files or furnishes annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, as well as any amendments to these reports, with the SEC. Through our website, www.devonenergy.com, we make available electronic copies of the documents we file or furnish to the SEC, the charters of the committees of our Board of Directors and other documents related to our corporate governance. The corporate governance documents available on our website include our Code of Ethics for Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer, and any amendments to and waivers from any provision of that Code will also be posted on our website. Access to these electronic filings is available free of charge as soon as reasonably practicable after filing or furnishing them to the SEC. Printed copies of our committee charters or other governance documents and filings can be requested by writing to our corporate secretary at the address on the cover of this report. Reports filed with the SEC are also made available on its website at www.sec.gov.

Our Strategy

Our business strategy is focused on delivering a consistently competitive shareholder return among our peer group. Because the business of exploring for, developing and producing oil and natural gas is capital intensive, delivering sustainable capital efficient cash flow growth is a key tenant to our success. While our cash flow is highly dependent on volatile and uncertain commodity prices, we pursue our strategy throughout all commodity price cycles with three fundamental principles.

A premier, sustainable portfolio of assets – As discussed in the next section of this Annual Report, we own a portfolio of assets located in the United States and Alberta, Canada. We strive to own premier assets capable of generating cash flows in excess of our capital and operating requirements, as well as competitive rates of return. We also desire to own a portfolio of assets that can provide a production growth platform extending many years into the future. Because of the strength of oil prices relative to natural gas, we have been positioning our portfolio to be more heavily weighted to U.S. oil assets in recent years.

During 2018, we made significant progress in our transition to a U.S. oil company. We sold our midstream business and certain non-core upstream assets, generating nearly $5 billion in proceeds. In February 2019, we announced our intent to separate our Canadian business and our Barnett Shale assets from the Company. After these separations, we expect our oil production growth, price realizations and field-level margins will all improve, as we sharpen our focus on four core U.S. oil plays located in the Delaware Basin, STACK, Eagle Ford and Rockies.

Superior execution – As we pursue cash flow growth, we continually work to optimize the efficiency of our capital programs and production operations, with an underlying objective of reducing absolute and per unit costs and enhancing our returns. We also strive to leverage our culture of health, safety and environmental stewardship in all aspects of our business.

Throughout 2018, we continued to achieve efficiency gains in various aspects of our business. Our initial production rates from new wells continued to improve in our four core U.S. oil plays and have exceeded the average of the top 40 U.S. producers since 2015 by more than 40%. We continued to improve cycle times, incorporate production optimization strategies and other cost reduction initiatives, driving down breakeven costs across our portfolio of assets.

As we focus on a more streamlined portfolio of U.S. oil assets, we are aggressively pursuing an improved cost structure with $780 million of annual costs savings expected by 2021. We expect to realize about 70% of the annualized savings by the end of 2019. Our retained U.S. oil business is expected to realize $300 million of annual well cost savings by 2021, as we increase our focus on development drilling, reduce our facility costs and optimize well spacing in the STACK. Additionally, we will streamline and align our workforce with our go-forward business, which should result in $300 million of annual cost savings by the end of the three-year period. As we continue deleveraging, we expect to reduce annual interest costs by $130 million. Finally, we have plans to reduce our annual production expenses by $50 million over the next three years.

Financial strength and flexibility – Commodity prices are uncertain and volatile, so we strive to maintain a strong balance sheet, as well as adequate liquidity and financial flexibility, in order to operate competitively in all commodity price cycles. Our capital allocation decisions are made with attention to these financial stewardship principles, as well as the priorities of funding our core operations, protecting our investment-grade credit ratings, and paying and growing our shareholder dividend.

6


Table of Contents

 

Index to Financial Statements

During 2018, we reduced our consolidated debt by 40%, primarily from our divestitures. We also raised our quarterly dividend 33% and began a $4 billion share repurchase program. As we dispose of our Canadian and Barnett Shale assets in 2019, we expect to use the proceeds to reduce debt further and repurchase additional common shares. As a result of our planned dispositions, our Board of Directors has increased our share repurchase program to $5 billion in February 2019 and raised our quarterly dividend 12.5% to $0.09 per share.

Oil and Gas Properties

Property Profiles

Key summary data from each of our areas of operation as of and for the year ended December 31, 2018 are detailed in the map below. Notes 22 and 23 to the financial statements included in “Item 8. Financial Statements and Supplementary Data” of this report contain additional information on our segments and geographical areas.

7


Table of Contents

 

Index to Financial Statements

Delaware Basin – The Delaware Basin is one of Devon’s top assets and continues to offer exploration and low-risk development opportunities from many geologic reservoirs and play types, including the oil-rich Bone Spring, Wolfcamp and Leonard formations. We expect these oil and liquids-rich opportunities across our acreage in the Delaware Basin to deliver high-margin growth for many years to come. During 2018, our continued appraisal and development work enabled us to increase our proved reserves in this area by approximately 24%. At December 31, 2018, we had 10 operated rigs developing this asset. In 2019, we plan to invest approximately $900 million of capital in the Delaware Basin, making it the top-funded asset in the portfolio.

STACK – The STACK development, located primarily in Oklahoma’s Canadian, Kingfisher and Blaine counties, is one of Devon’s top assets. Our STACK position is one of the largest in the industry, providing visible long-term stable production. At December 31, 2018, we had five operated rigs with drilling focused in the Meramec formation. In 2019, we plan approximately $400 million of capital investment. The STACK is Devon’s second highest funded asset in the portfolio for 2019.

Eagle Ford – We acquired our position in the Eagle Ford in 2014. Since acquiring these assets, we have delivered tremendous results by producing 173 million oil-equivalent barrels. Our excellent results are driven by our development in DeWitt County, located in the economic core of the play. Our Eagle Ford assets generated significant cash flow in 2018. In 2019, we plan approximately $300 million of capital investment.

Rockies Oil – Our acreage in the Rockies is focused on emerging oil opportunities in the Powder River Basin. Recent drilling success in this basin has expanded our drilling inventory, and we expect further growth as we accelerate activity and continue to de-risk this emerging light-oil opportunity. As of December 31, 2018, we had two operated rigs targeting the Turner, Parkman, Teapot and Niobrara formations in northern Converse County of the Powder River Basin. In 2019, we plan approximately $300 million of capital investment and adding two additional operated rigs.

Heavy Oil – Our operations in Canada are focused on our heavy oil assets in Alberta, Canada. Our most significant Canadian operation is our Jackfish complex, an industry-leading thermal heavy oil operation in the non-conventional oil sands of east central Alberta. We employ a recovery method known as steam-assisted gravity drainage at Jackfish. The Jackfish operation consists of three facilities. We expect Jackfish to maintain a reasonably flat production profile for greater than 15 years requiring approximately $200 million of annual maintenance capital based on current economic conditions.

Our Pike oil sands acreage is situated directly to the southeast of our Jackfish acreage in east central Alberta and has similar reservoir characteristics to Jackfish. The Pike leasehold is currently undeveloped and has no proved reserves or production as of December 31, 2018. Currently, we have minimal planned capital outlays for Pike in the near future. The majority of our Pike leasehold does not expire until 2025 and 2026.

In addition to Jackfish and Pike, we hold acreage and own producing assets in the Bonnyville region, located to the south and east of Jackfish in eastern Alberta. Bonnyville is a low-risk oil development play that produces heavy oil by conventional means, without the need for steam injection.

In 2019, we plan to separate our operations in Canada.

Barnett Shale – This is our largest property in terms of proved reserves. Our leases are located primarily in Denton, Parker, Tarrant and Wise counties in north Texas. Since acquiring a substantial position in this field in 2002, we continue to introduce technology and new innovations to optimize production operations and have transformed this asset into one of the top producing gas fields in North America. In 2019, we plan to separate our Barnett Shale assets.

Proved Reserves

For estimates of our proved developed and proved undeveloped reserves and the discussion of the contribution by each property, see Note 23 in “Item 8. Financial Statements and Supplementary Data” of this report.

Proved oil and gas reserves are those quantities of oil, gas and NGLs which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from known reservoirs under existing economic conditions, operating methods and government regulations. To be considered proved, oil and gas reserves must be economically producible before contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. Also, 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.

8


Table of Contents

 

Index to Financial Statements

The process of estimating oil, gas and NGL reserves is complex and requires significant judgment, as discussed in “Item 1A. Risk Factors” of this report. As a result, we have developed internal policies for estimating and recording reserves. Such policies require proved reserves to be in compliance with the SEC definitions and guidance. Our policies assign responsibilities for compliance in reserves bookings to our Reserve Evaluation Group (the “Group”). These same policies also require that reserve estimates be made by professionally qualified reserves estimators, as defined by the Society of Petroleum Engineers’ standards.

The Group, which is led by Devon’s Director of Reserves and Economics, is responsible for the internal review and certification of reserves estimates. We ensure the Director and key members of the Group have appropriate technical qualifications to oversee the preparation of reserves estimates. The Group reports to and is managed through our finance department. No portion of the Group’s compensation is directly dependent on the quantity of reserves booked.

The Director of the Group has over 30 years of industry experience with positions of increasing responsibility for the estimation and evaluation of reserves. He has been employed by Devon for the past 18 years, including the past 11 in his current position. His further professional qualifications include a degree in petroleum engineering, registered professional engineer, member of the Society of Petroleum Engineers and experience in reserves estimation for projects in the U.S. (both onshore and offshore), as well as in Canada, Asia, the Middle East and South America.  

Throughout the year, the Group performs internal reserves reviews of each operating country’s reserves. The Group also oversees audits and reserves estimates performed by qualified third-party petroleum consulting firms. During 2018, we engaged two such firms to audit approximately 89% of our proved reserves in accordance with generally accepted petroleum engineering and evaluation methods and procedures. LaRoche Petroleum Consultants, Ltd. audited approximately 87% of our U.S. reserves, and Deloitte LLP audited approximately 97% of our Canadian reserves.

In addition to conducting these internal reviews and external reserves audits, we also have a Reserves Committee that consists of three independent members of our Board of Directors. This committee provides additional oversight of our reserves estimation and certification process. The members of our Reserves Committee have educational backgrounds in geology or petroleum engineering, as well as experience relevant to the reserves estimation process. The Reserves Committee meets a minimum of twice a year to discuss reserves issues and policies and meets at least once a year separately with our senior reserves engineering personnel and separately with our third-party petroleum consultants.

The following tables present production, price and cost information for each significant field, country and continent.

 

 

 

Production

 

Year Ended December 31,

 

Oil (MMBbls)

 

 

Bitumen (MMBbls)

 

 

Gas (Bcf)

 

 

NGLs (MMBbls)

 

 

Total (MMBoe)

 

2018

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Barnett Shale

 

 

 

 

 

 

 

 

186

 

 

 

12

 

 

 

43

 

STACK

 

 

12

 

 

 

 

 

 

121

 

 

 

14

 

 

 

45

 

Jackfish

 

 

 

 

 

35

 

 

 

 

 

 

 

 

 

35

 

U.S.

 

 

47

 

 

 

 

 

 

397

 

 

 

39

 

 

 

153

 

Canada

 

 

7

 

 

 

35

 

 

 

4

 

 

 

 

 

 

42

 

Total North America

 

 

54

 

 

 

35

 

 

 

401

 

 

 

39

 

 

 

195

 

2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Barnett Shale

 

 

 

 

 

 

 

 

237

 

 

 

14

 

 

 

54

 

STACK

 

 

9

 

 

 

 

 

 

107

 

 

 

11

 

 

 

38

 

Jackfish

 

 

 

 

 

40

 

 

 

 

 

 

 

 

 

40

 

U.S.

 

 

42

 

 

 

 

 

 

433

 

 

 

36

 

 

 

150

 

Canada

 

 

7

 

 

 

40

 

 

 

6

 

 

 

 

 

 

48

 

Total North America

 

 

49

 

 

 

40

 

 

 

439

 

 

 

36

 

 

 

198

 

2016

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Barnett Shale

 

 

 

 

 

 

 

 

265

 

 

 

15

 

 

 

60

 

STACK

 

 

7

 

 

 

 

 

 

103

 

 

 

9

 

 

 

33

 

Jackfish

 

 

 

 

 

40

 

 

 

 

 

 

 

 

 

40

 

U.S.

 

 

47

 

 

 

 

 

 

510

 

 

 

42

 

 

 

174

 

Canada

 

 

8

 

 

 

40

 

 

 

7

 

 

 

 

 

 

49

 

Total North America

 

 

55

 

 

 

40

 

 

 

517

 

 

 

42

 

 

 

223

 

9


Table of Contents

 

Index to Financial Statements

 

 

 

Average Sales Price (1)

 

 

 

 

 

Year Ended December 31,

 

Oil (Per Bbl)

 

 

Bitumen (Per Bbl)

 

 

Gas (Per Mcf)

 

 

NGLs (Per Bbl)

 

 

Production Cost (Per Boe) (1)(2)

 

2018 (1)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Barnett Shale

 

$

62.89

 

 

$

 

 

$

2.45

 

 

$

22.72

 

 

$

9.42

 

STACK

 

$

63.81

 

 

$

 

 

$

2.29

 

 

$

25.53

 

 

$

7.16

 

Jackfish

 

$

 

 

$

17.88

 

 

$

 

 

$

 

 

$

12.85

 

U.S.

 

$

61.97

 

 

$

 

 

$

2.37

 

 

$

24.74

 

 

$

8.61

 

Canada

 

$

27.36

 

 

$

17.88

 

 

N/M

 

 

$

 

 

$

13.43

 

Total North America

 

$

57.76

 

 

$

17.88

 

 

$

2.37

 

 

$

24.74

 

 

$

9.66

 

2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Barnett Shale

 

$

49.72

 

 

$

 

 

$

2.47

 

 

$

13.67

 

 

$

6.86

 

STACK

 

$

48.43

 

 

$

 

 

$

2.40

 

 

$

17.78

 

 

$

4.72

 

Jackfish

 

$

 

 

$

29.38

 

 

$

 

 

$

 

 

$

11.02

 

U.S.

 

$

49.41

 

 

$

 

 

$

2.48

 

 

$

15.66

 

 

$

6.74

 

Canada

 

$

33.73

 

 

$

29.38

 

 

N/M

 

 

$

 

 

$

11.70

 

Total North America

 

$

47.31

 

 

$

29.38

 

 

$

2.48

 

 

$

15.66

 

 

$

7.94

 

2016

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Barnett Shale

 

$

41.03

 

 

$

 

 

$

1.76

 

 

$

10.31

 

 

$

5.75

 

STACK

 

$

39.81

 

 

$

 

 

$

1.91

 

 

$

10.86

 

 

$

4.34

 

Jackfish

 

$

 

 

$

19.82

 

 

$

 

 

$

 

 

$

8.70

 

U.S.

 

$

38.92

 

 

$

 

 

$

1.84

 

 

$

9.81

 

 

$

6.44

 

Canada

 

$

23.96

 

 

$

19.82

 

 

N/M

 

 

$

 

 

$

9.36

 

Total North America

 

$

36.72

 

 

$

19.82

 

 

$

1.84

 

 

$

9.81

 

 

$

7.08

 

 

 

(1)

As further discussed in Note 1 in “Item 8. Financial Statements and Supplementary Data” of this report, in 2018 the presentation of certain processing arrangements changed from a net to a gross presentation. The change resulted in an increase to our upstream revenues and production expenses by $254 million during 2018 with no impact to net earnings. These changes primarily related to our Barnett Shale and STACK properties.

 

(2)

Represents production expense per BOE excluding production and property taxes. Jackfish and Canada include purchases of natural gas used to heat the heavy oil reservoirs. The gas is purchased at prevailing market prices, which vary from year to year.

Drilling Statistics

The following table summarizes our development and exploratory drilling results.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Development Wells (1)

 

 

Exploratory Wells (1)

 

 

Total Wells (1)

 

Year Ended December 31,

 

Productive

 

 

Dry

 

 

Productive

 

 

Dry

 

 

Productive

 

 

Dry

 

 

Total

 

2018

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

U.S.

 

 

165.6

 

 

 

3.1

 

 

 

69.4

 

 

 

 

 

 

235.0

 

 

 

3.1

 

 

 

238.1

 

Canada

 

 

70.5

 

 

 

 

 

 

 

 

 

 

 

 

70.5

 

 

 

 

 

 

70.5

 

Total North America

 

 

236.1

 

 

 

3.1

 

 

 

69.4

 

 

 

 

 

 

305.5

 

 

 

3.1

 

 

 

308.6

 

2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

U.S.

 

 

149.8

 

 

 

 

 

 

44.0

 

 

 

 

 

 

193.8

 

 

 

 

 

 

193.8

 

Canada

 

 

100.5

 

 

 

 

 

 

 

 

 

 

 

 

100.5

 

 

 

 

 

 

100.5

 

Total North America

 

 

250.3

 

 

 

 

 

 

44.0

 

 

 

 

 

 

294.3

 

 

 

 

 

 

294.3

 

2016

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

U.S.

 

 

88.5

 

 

 

 

 

 

36.4

 

 

 

2.0

 

 

 

124.9

 

 

 

2.0

 

 

 

126.9

 

Canada

 

 

21.5

 

 

 

 

 

 

 

 

 

 

 

 

21.5

 

 

 

 

 

 

21.5

 

Total North America

 

 

110.0

 

 

 

 

 

 

36.4

 

 

 

2.0

 

 

 

146.4

 

 

 

2.0

 

 

 

148.4

 

 

(1)

Well counts represent net wells completed during each year. Net wells are gross wells multiplied by our fractional working interests.

10


Table of Contents

 

Index to Financial Statements

The following table presents the wells that were in progress on December 31, 2018. As of February 1, 2019, these wells were still in progress.

 

 

 

Gross (1)

 

 

Net (2)

 

U.S.

 

 

184.0

 

 

 

105.2

 

Canada

 

 

1.0

 

 

 

1.0

 

Total North America

 

 

185.0

 

 

 

106.2

 

 

(1)

Gross wells are the sum of all wells in which we own a working interest.

(2)

Net wells are gross wells multiplied by our fractional working interests in each well.

Productive Wells

The following table sets forth our producing wells as of December 31, 2018.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil Wells (1)

 

 

Natural Gas Wells

 

 

Total Wells (1)

 

 

 

Gross (2)(4)

 

 

Net (3)

 

 

Gross (2)(4)

 

 

Net (3)

 

 

Gross (2)(4)

 

 

Net (3)

 

U.S.

 

 

9,284

 

 

 

3,445

 

 

 

8,235

 

 

 

5,703

 

 

 

17,519

 

 

 

9,148

 

Canada

 

 

3,183

 

 

 

3,071

 

 

 

544

 

 

 

380

 

 

 

3,727

 

 

 

3,451

 

Total North America

 

 

12,467

 

 

 

6,516

 

 

 

8,779

 

 

 

6,083

 

 

 

21,246

 

 

 

12,599

 

 

(1)

Includes bitumen wells.

(2)

Gross wells are the sum of all wells in which we own a working interest.

(3)

Net wells are gross wells multiplied by our fractional working interests in each well.

(4)

Includes 902 and 350 gross oil and gas wells, respectively, which had multiple completions.

The day-to-day operations of oil and gas properties are the responsibility of an operator designated under pooling or operating agreements. The operator supervises production, maintains production records, employs field personnel and performs other functions. We are the operator of approximately 12,900 gross wells. As operator, we receive reimbursement for direct expenses incurred to perform our duties, as well as monthly per-well producing, drilling, and construction overhead reimbursement at rates customarily charged in the respective areas. In presenting our financial data, we record the monthly overhead reimbursements as a reduction of G&A, which is a common industry practice.

Acreage Statistics

The following table sets forth our developed and undeveloped lease and mineral acreage as of December 31, 2018. Of our 3.8 million net acres, approximately 1.9 million acres are held by production. The acreage in the table includes 0.2 million, 0.1 million and 0.1 million net acres subject to leases that are scheduled to expire during 2019, 2020 and 2021, respectively. As of December 31, 2018, there were no proved undeveloped reserves associated with our expiring acreage. Of the 0.3 million net acres set to expire by December 31, 2021, we anticipate performing operational and administrative actions to continue the lease terms for portions of the acreage that we intend to further assess. However, we do expect to allow a portion of the acreage to expire in the normal course of business. In 2018, we allowed approximately 0.1 million acres to expire.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Developed

 

 

Undeveloped

 

 

Total

 

 

 

Gross (1)

 

 

Net (2)

 

 

Gross (1)

 

 

Net (2)

 

 

Gross (1)

 

 

Net (2)

 

 

 

(Thousands)

 

U.S.

 

 

1,449

 

 

 

909

 

 

 

3,373

 

 

 

1,463

 

 

 

4,822

 

 

 

2,372

 

Canada

 

 

674

 

 

 

495

 

 

 

2,086

 

 

 

967

 

 

 

2,760

 

 

 

1,462

 

Total North America

 

 

2,123

 

 

 

1,404

 

 

 

5,459

 

 

 

2,430

 

 

 

7,582

 

 

 

3,834

 

 

(1)

Gross acres are the sum of all acres in which we own a working interest.

(2)

Net acres are gross acres multiplied by our fractional working interests in the acreage.

11


Table of Contents

 

Index to Financial Statements

Title to Properties

Title to properties is subject to contractual arrangements customary in the oil and gas industry, liens for taxes not yet due and, in some instances, other encumbrances. We believe that such burdens do not materially detract from the value of properties or from the respective interests therein or materially interfere with their use in the operation of the business.

As is customary in the industry, a preliminary title investigation, typically consisting of a review of local title records, is made at the time of acquisitions of undeveloped properties. More thorough title investigations, which generally include a review of title records and the preparation of title opinions by outside legal counsel, are made prior to the consummation of an acquisition of producing properties and before commencement of drilling operations on undeveloped properties.

Marketing Activities

Oil, Gas and NGL Marketing

The spot markets for oil, gas and NGLs are subject to volatility as supply and demand factors fluctuate. As detailed below, we sell our production under both long-term (one year or more) and short-term (less than one year) agreements at prices negotiated with third parties. Regardless of the term of the contract, the vast majority of our production is sold at variable, or market-sensitive, prices.

Additionally, we may enter into financial hedging arrangements or fixed-price contracts associated with a portion of our oil, gas and NGL production. These activities are intended to support targeted price levels and to manage our exposure to price fluctuations. See Note 3 in “Item 8. Financial Statements and Supplementary Data” of this report for further information.

As of January 2019, our production was sold under the following contract terms.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Short-Term

 

 

Long-Term

 

 

 

Variable

 

 

Fixed

 

 

Variable

 

 

Fixed

 

Oil and bitumen

 

 

75

%

 

 

 

 

 

25

%

 

 

 

Natural gas

 

 

67

%

 

 

4

%

 

 

29

%

 

 

 

NGLs

 

 

41

%

 

 

20

%

 

 

39

%

 

 

 

 

Delivery Commitments

A portion of our production is sold under certain contractual arrangements that specify the delivery of a fixed and determinable quantity. As of December 31, 2018, we were committed to deliver the following fixed quantities of production.

 

 

 

Total

 

 

Less Than 1 Year

 

 

1-3 Years

 

 

3-5 Years

 

Oil and bitumen (MMBbls)

 

 

53

 

 

 

25

 

 

 

28

 

 

 

 

Natural gas (Bcf)

 

 

360

 

 

 

220

 

 

 

125

 

 

 

15

 

NGLs (MMBbls)

 

 

10

 

 

 

10

 

 

 

 

 

 

 

Total (MMBoe)

 

 

123

 

 

 

72

 

 

 

49

 

 

 

2

 

 

We expect to fulfill our delivery commitments primarily with production from our proved developed reserves. Moreover, our proved reserves have generally been sufficient to satisfy our delivery commitments during the three most recent years, and we expect such reserves will continue to be the primary means of fulfilling our future commitments. However, where our proved reserves are not sufficient to satisfy our delivery commitments, we can and may use spot market purchases to satisfy the commitments.

Customers

During 2018, we had one purchaser that accounted for approximately 11% of our consolidated sales revenue.

During 2017 and 2016, no purchaser accounted for over 10% of our consolidated sales revenue.

Competition

See “Item 1A. Risk Factors.”

12


Table of Contents

 

Index to Financial Statements

Public Policy and Government Regulation

Our industry is subject to a wide range of regulations. Laws, rules, regulations, taxes, fees and other policy implementation actions affecting our industry have been pervasive and are under constant review for amendment or expansion. Numerous government agencies have issued extensive regulations which are binding on our industry and its individual members, some of which carry substantial penalties for failure to comply. These laws and regulations increase the cost of doing business and consequently affect profitability. Because public policy changes are commonplace, and existing laws and regulations are frequently amended, we are unable to predict the future cost or impact of compliance. However, we do not expect that any of these laws and regulations will affect our operations materially differently than they would affect other companies with similar operations, size and financial strength. The following are significant areas of government control and regulation affecting our operations.

Exploration and Production Regulation

Our operations are subject to federal, tribal, state, provincial and local laws and regulations. These laws and regulations relate to matters that include:

 

acquisition of seismic data;

 

location, drilling and casing of wells;

 

well design;

 

hydraulic fracturing;

 

well production;

 

spill prevention plans;

 

emissions and discharge permitting;

 

use, transportation, storage and disposal of fluids and materials incidental to oil and gas operations;

 

surface usage and the restoration of properties upon which wells have been drilled;

 

calculation and disbursement of royalty payments and production taxes;

 

plugging and abandoning of wells;

 

transportation of production; and

 

endangered species and habitat.

Our operations also are subject to conservation regulations, including the regulation of the size of drilling and spacing units or proration units; the number of wells that may be drilled in a unit; the rate of production allowable from oil and gas wells; and the unitization or pooling of oil and gas properties. In the U.S., some states allow the forced pooling or unitization of tracts to facilitate exploration, while other states rely on voluntary pooling of lands and leases, which may make it more difficult to develop oil and gas properties. In addition, federal and state conservation laws generally limit the venting or flaring of natural gas, and state conservation laws impose certain requirements regarding the ratable purchase of production. These regulations limit the amounts of oil and gas we can produce from our wells and the number of wells or the locations at which we can drill.

Certain of our U.S. natural gas and oil leases are granted or approved by the federal government and administered by the BLM or Bureau of Indian Affairs of the Department of the Interior. Such leases require compliance with detailed federal regulations and orders that regulate, among other matters, drilling and operations on lands covered by these leases and calculation and disbursement of royalty payments to the federal government, tribes or tribal members. The federal government has, from time to time, evaluated and, in some cases, promulgated new rules and regulations regarding competitive lease bidding, venting and flaring, oil and gas measurement and royalty payment obligations for production from federal lands. In addition, permitting activities on federal lands can sometimes be subject to delays.

Royalties and Incentives in Canada

The royalty calculation in Canada is a significant factor in the profitability of Canadian oil and gas production. Oil sands crown royalties are determined by government regulations and are generally calculated as a percentage of the value of the gross production, net of allowed deductions. The royalty percentage is determined on a sliding-scale based on crown posted prices. For pre-payout oil sands projects, the regulations prescribe lower royalty rates for oil sands projects until allowable capital costs have been recovered. In

13


Table of Contents

 

Index to Financial Statements

early 2016, the Alberta government adopted the recommendation of its Royalty Review Panel. The new royalty framework preserves the existing royalty structure and rates for oil sands. For conventional oil and gas royalty calculations, wells drilled after January 1, 2017 would use the Modernized Royalty Framework (MRF) which prescribes a lower royalty rate until allowable costs have been recovered. The calculation for wells post payout is based on a percentage of production net of allowed deductions and varies with commodity price. 

Marketing in Canada

Any oil or gas export requires an exporter to obtain export authorizations from Canada’s National Energy Board.

In December 2018, Alberta enacted the Curtailment Rules (Rules) in an effort to reduce Alberta’s oversupply of oil which resulted from pipeline and rail constraints. Pursuant to the Rules, operators that produce either or both crude oil or crude bitumen in amounts in excess of 10 MBbls/d are required to curtail their production. As of January 1, 2019, the production curtailment amount was set at 325 MBbls/d. The curtailment amounts are expected to reduce over 2019 to an average of approximately 95 MBbls/d as storage levels ease and price differential improve, and the Rules terminate on December 31, 2019. Devon’s curtailments in the first quarter of 2019 as a result of the Rules are anticipated to total approximately 10 MBbls/d of bitumen, or approximately 2% of our total production.

Environmental, Pipeline Safety and Occupational Regulations

We strive to conduct our operations in a socially and environmentally responsible manner, which includes compliance with applicable law. We are subject to many federal, state, provincial, tribal and local laws and regulations concerning occupational safety and health as well as the discharge of materials into, and the protection of, the environment and natural resources. Environmental laws and regulations relate to:

 

the discharge of pollutants into federal, provincial and state waters;

 

assessing the environmental impact of seismic acquisition, drilling or construction activities;

 

the generation, storage, transportation and disposal of waste materials, including hazardous substances;

 

the emission of certain gases into the atmosphere;

 

the monitoring, abandonment, reclamation and remediation of well and other sites, including sites of former operations;

 

the development of emergency response and spill contingency plans;

 

the monitoring, repair and design of pipelines used for the transportation of oil and natural gas;

 

the protection of threatened and endangered species; and

 

worker protection.

Failure to comply with these laws and regulations can lead to the imposition of remedial liabilities, administrative, civil or criminal fines or penalties or injunctions limiting our operations in affected areas. Moreover, multiple environmental laws provide for citizen suits, which allow environmental organizations to act in the place of the government and sue operators for alleged violations of environmental law. Environmental protection and health and safety compliance are necessary, manageable parts of our business. We have been able to plan for and comply with environmental, safety and health initiatives without materially altering our operating strategy or incurring significant unreimbursed expenditures. However, based on regulatory trends and increasingly stringent laws, our capital expenditures and operating expenses related to the protection of the environment and safety and health compliance have increased over the years and may continue to increase. We cannot predict with any reasonable degree of certainty our future exposure concerning such matters.

 

 

Item 1A. Risk Factors

Our business and operations, and our industry in general, are subject to a variety of risks. The risks described below may not be the only risks we face, as our business and operations may also be subject to risks that we do not yet know of, or that we currently believe are immaterial. If any of the following risks should occur, our business, financial condition, results of operations and liquidity could be materially and adversely impacted. As a result, holders of our securities could lose part or all of their investment in Devon.

14


Table of Contents

 

Index to Financial Statements

Volatile Oil, Gas and NGL Prices Significantly Impact our Business

Our financial condition, results of operations and the value of our properties are highly dependent on the general supply and demand for oil, gas and NGLs, which impact the prices we ultimately realize on our sales of these commodities. Historically, market prices and our realized prices have been volatile. For example, over the last five years, NYMEX WTI oil and NYMEX Henry Hub prices ranged from a high of over $100 per Bbl and $6 per MMBtu, respectively, to a low of under $27 per Bbl and $1.70 per MMBtu, respectively. Such volatility is likely to continue in the future due to numerous factors beyond our control, including, but not limited to:

 

the domestic and worldwide supply of and demand for oil, gas and NGLs;

 

volatility and trading patterns in the commodity-futures markets;

 

conservation and environmental protection efforts;

 

production levels of members of OPEC, Russia or other producing countries;

 

geopolitical risks, including political and civil unrest in the Middle East, Africa and South America;

 

adverse weather conditions and natural disasters, such as tornadoes, earthquakes and hurricanes;

 

regional pricing differentials, including in Canada, the Delaware Basin and other areas of our operations;

 

differing quality of production, including NGL content of gas produced;

 

the level of imports and exports of oil, gas and NGLs and the level of global oil, gas and NGL inventories;

 

the price and availability of alternative fuels;

 

technological advances affecting energy consumption and production;

 

the overall economic environment;

 

changes in trade relations and policies, including the imposition of tariffs by the U.S. or China; and

 

other governmental regulations and taxes.

The differential between WTI and Western Canadian Select, a benchmark for the Canadian oil market, recently expanded, widening to nearly $46 per barrel in November 2018. As a result, our Canadian heavy oil unhedged realized price for the fourth quarter was near zero. This negatively affected our results of operations in 2018, and a sustained weakness or further deterioration in differentials or commodity prices could materially and adversely impact our business by resulting in, or exacerbating, the following effects:

 

reducing the amount of oil, bitumen, gas and NGLs that we can produce economically;

 

limiting our financial flexibility, liquidity and access to sources of capital, such as equity and debt;

 

reducing our revenues, operating cash flows and profitability;

 

causing us to decrease our capital expenditures or maintain reduced capital spending for an extended period, resulting in lower future production of oil, gas and NGLs; and

 

reducing the carrying value of our properties, resulting in noncash write-downs.

Estimates of Oil, Gas and NGL Reserves Are Uncertain and May Be Subject to Revision

The process of estimating oil, gas and NGL reserves is complex and requires significant judgment in the evaluation of available geological, engineering and economic data for each reservoir, particularly for new discoveries. Because of the high degree of judgment involved, different reserve engineers may develop different estimates of reserve quantities and related revenue based on the same data. In addition, the reserve estimates for a given reservoir may change substantially over time as a result of several factors, including additional development and appraisal activity, the viability of production under varying economic conditions, including commodity price declines, and variations in production levels and associated costs. Consequently, material revisions to existing reserve estimates may occur as a result of changes in any of these factors. Such revisions to proved reserves could have a material adverse effect on our financial condition and the value of our properties, as well as the estimates of our future net revenue and profitability. Our policies and internal controls related to estimating and recording reserves are included in “Items 1 and 2. Business and Properties” of this report.

15


Table of Contents

 

Index to Financial Statements

Discoveries or Acquisitions of Reserves Are Needed to Avoid a Material Decline in Reserves and Production

The production rates from oil and gas properties generally decline as reserves are depleted, while related per unit production costs generally increase due to decreasing reservoir pressures and other factors. Therefore, our estimated proved reserves and future oil, gas and NGL production will decline materially as reserves are produced unless we conduct successful exploration and development activities, such as identifying additional producing zones in existing wells, utilizing secondary or tertiary recovery techniques or acquiring additional properties containing proved reserves. Consequently, our future oil, gas and NGL production and related per unit production costs are highly dependent upon our level of success in finding or acquiring additional reserves.

Our Operations Are Uncertain and Involve Substantial Costs and Risks

Our operating activities are subject to numerous costs and risks, including the risk that we will not encounter commercially productive oil or gas reservoirs. Drilling for oil, gas and NGLs can be unprofitable, not only from dry holes, but from productive wells that do not return a profit because of insufficient revenue from production or high costs. Substantial costs are required to locate, acquire and develop oil and gas properties, and we are often uncertain as to the amount and timing of those costs. Our cost of drilling, completing, equipping and operating wells is often uncertain before drilling commences. Declines in commodity prices and overruns in budgeted expenditures are common risks that can make a particular project uneconomic or less economic than forecasted. While both exploratory and developmental drilling activities involve these risks, exploratory drilling involves greater risks of dry holes or failure to find commercial quantities of hydrocarbons. In addition, our oil and gas properties can become damaged, our operations may be curtailed, delayed or canceled and the costs of such operations may increase as a result of a variety of factors, including, but not limited to:

 

unexpected drilling conditions, pressure conditions or irregularities in reservoir formations;

 

equipment failures or accidents;

 

fires, explosions, blowouts, cratering or loss of well control, as well as the mishandling or underground migration of fluids and chemicals;

 

adverse weather conditions and natural disasters, such as tornadoes, earthquakes, hurricanes and extreme temperatures;

 

issues with title or in receiving governmental permits or approvals;

 

restricted takeaway capacity for our production, including due to inadequate midstream infrastructure or constrained downstream markets;

 

environmental hazards or liabilities;

 

restrictions in access to, or disposal of, water used or produced in drilling and completion operations; and

 

shortages or delays in the availability of services or delivery of equipment.

The occurrence of one or more of these factors could result in a partial or total loss of our investment in a particular property, as well as significant liabilities. Moreover, certain of these events could result in environmental pollution and impact to third parties, including persons living in proximity to our operations, our employees and employees of our contractors, leading to possible injuries, death or significant damage to property and natural resources.

In addition, we rely on our employees, consultants and sub-contractors to conduct our operations in compliance with applicable laws and standards. Any violation of such laws or standards by these individuals, whether through negligence, harassment, discrimination or other misconduct, could result in significant liability for us and adversely affect our business. For example, negligent operations by employees could result in serious injury, death or property damage, and sexual harassment or racial and gender discrimination could result in legal claims and reputational harm.

 

We Are Subject to Extensive Governmental Regulation, Which Can Change and Could Adversely Impact Our Business

Our operations are subject to extensive federal, state, provincial, tribal, local and other laws, rules and regulations, including with respect to environmental matters, worker health and safety, wildlife conservation, the gathering and transportation of oil, gas and NGLs, conservation policies, reporting obligations, royalty payments, unclaimed property and the imposition of taxes. Such

16


Table of Contents

 

Index to Financial Statements

regulations include requirements for permits to drill and to conduct other operations and for provision of financial assurances (such as bonds) covering drilling, completion and well operations and decommissioning obligations. If permits are not issued, or if unfavorable restrictions or conditions are imposed on our drilling or completion activities, we may not be able to conduct our operations as planned. In addition, we may be required to make large expenditures to comply with applicable governmental laws, rules, regulations, permits or orders. For example, certain regulations require the plugging and abandonment of wells and removal of production facilities by current and former operators, which may result in significant costs associated with the removal of tangible equipment and other restorative actions at the end of operations.

In addition, changes in public policy have affected, and in the future could further affect, our operations. Regulatory and public policy developments could, among other things, restrict production levels, impose price controls, change environmental protection requirements and increase taxes, royalties and other amounts payable to governments or governmental agencies. Our operating and other compliance costs could increase further if existing laws and regulations are revised or reinterpreted or if new laws and regulations become applicable to our operations. In addition, changes in public policy may indirectly impact our operations by, among other things, increasing the cost of supplies and equipment and fostering general economic uncertainty. For example, changes in U.S. trade relations, particularly the imposition of tariffs by the U.S. and China, may increase the cost of materials we or our vendors use, thereby increasing our operating expense. Although we are unable to predict changes to existing laws and regulations, such changes could significantly impact our profitability, financial condition and liquidity, particularly changes related to hydraulic fracturing, pipeline safety, seismic activity and income taxes, as discussed below.

Hydraulic Fracturing – In recent years, the EPA has made proposals that subject hydraulic fracturing to further regulation and that could potentially restrict the practice of hydraulic fracturing. For example, the EPA has issued final regulations under the federal Clean Air Act establishing performance standards for oil and gas activities, including standards for the capture of air emissions released during hydraulic fracturing, and finalized in 2016 regulations that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. The EPA also released a study in 2016 finding that certain aspects of hydraulic fracturing, such as water withdrawals and wastewater management practices, could result in impacts to water resources, although the report did not identify a direct link between hydraulic fracturing and impacts to groundwater resources. The BLM previously finalized regulations to regulate hydraulic fracturing on federal lands, but subsequently issued a repeal of those regulations in 2017. Several states in which we operate have already adopted and more states are considering adopting laws or regulations that require disclosure of chemicals used in hydraulic fracturing and impose more stringent permitting, disclosure and well-construction requirements on hydraulic fracturing operations. In addition, some states and municipalities have significantly limited drilling activities or hydraulic fracturing or are considering doing so or banning the practice altogether. Although it is not possible at this time to predict the final outcome of these proposals, any new federal, state or local restrictions on hydraulic fracturing that may be imposed in areas in which we conduct business could potentially result in increased compliance costs, delays in development or restrictions on our operations.

Pipeline Safety – The pipeline assets in which we own interests, are subject to stringent and complex regulations related to pipeline safety and integrity management. The PHMSA has established a series of rules that require pipeline operators to develop and implement integrity management programs for gas, NGL and condensate transmission pipelines as well as certain low stress pipelines and gathering lines transporting hazardous liquids, such as oil, that, in the event of a failure, could affect “high consequence areas.” Additional action by PHMSA with respect to pipeline integrity management requirements may occur in the future. For example, in 2016 PHMSA proposed new rules for gas pipelines that extend pipeline safety programs beyond high consequence areas to newly proposed “moderate consequence areas” and would also impose more rigorous testing and reporting requirements on such pipelines. To date, no further action has been taken. PHMSA has announced its intent to address the 2016 proposed rules for gas pipelines through three separate final rulemakings in 2019. More recently, in January 2017, PHMSA finalized regulations for hazardous liquid pipelines that significantly extend and expand the reach of certain PHMSA integrity management requirements (i.e., periodic assessments, leak detection and repairs), regardless of the pipeline’s proximity to a high consequence area. The final rule also imposes new reporting requirements for certain unregulated pipelines, including all hazardous liquid gathering lines. Following the change in presidential administrations, implementation of this rule was delayed, but the final rule is expected to be published in the Federal Register and become effective during the first half of 2019. At this time, we cannot predict the cost of such requirements, but they could be significant. Moreover, violations of pipeline safety regulations can result in the imposition of significant penalties.

Seismic Activity – Earthquakes in northern and central Oklahoma and elsewhere have prompted concerns about seismic activity and possible relationships with the energy industry. Legislative and regulatory initiatives intended to address these concerns may result in additional levels of regulation or other requirements that could lead to operational delays, increase our operating and compliance costs or otherwise adversely affect our operations. In addition, we are currently defending against certain third-party lawsuits and could be subject to additional claims, seeking alleged property damages or other remedies as a result of alleged induced seismic activity in our areas of operation.  

17


Table of Contents

 

Index to Financial Statements

Changes to Tax Laws – We are subject to U.S. federal income tax as well as income or capital taxes in various state and foreign jurisdictions, and our operating cash flow is sensitive to the amount of income taxes we must pay. In the jurisdictions in which we operate, income taxes are assessed on our earnings after consideration of all allowable deductions and credits. Changes in the types of earnings that are subject to income tax, the types of costs that are considered allowable deductions or the rates assessed on our taxable earnings would all impact our income taxes and resulting operating cash flow.

Concerns About Climate Change and Related Regulatory, Social and Market Actions May Adversely Affect Our Business

Continuing and increasing political and social attention to the issue of climate change has resulted in legislative, regulatory and other initiatives, including international agreements, to reduce greenhouse gas emissions, such as carbon dioxide and methane. Policy makers at both the U.S. federal and state levels have introduced legislation and proposed new regulations designed to quantify and limit the emission of greenhouse gases. For example, both the EPA and the BLM have issued regulations for the control of methane emissions, which also include leak detection and repair requirements, for the oil and gas industry. Following the change in presidential administrations, however, the agencies have attempted to revise or rescind their previously issued methane standards. Litigation concerning these methane regulations and subsequent attempts to revise or rescind them is ongoing. Nevertheless, several states where we operate, including Wyoming, have already imposed venting and flaring limitations designed to reduce methane emissions from oil and gas exploration and production activities. With respect to more comprehensive regulation, federal and state initiatives to date have generally focused on the development of cap-and-trade or carbon tax programs. As generally proposed, a cap-and-trade program would cap overall greenhouse gas emissions on an economy-wide basis and require major sources of greenhouse gas emissions or major fuel producers to acquire and surrender emission allowances, while a carbon tax could impose taxes based on emissions from our operations and downstream uses of our products.  

In Canada, greenhouse gas emissions are also being addressed at both the federal and provincial level. Devon will continue to be subject to Alberta’s climate change laws and regulations until at least 2021. Those laws and regulations include a legislated oil sands emission limit, with forthcoming regulations involving methane emissions reduction targets. Beginning January 2019, the Greenhouse Gas Pollution Pricing Act subjects all of Canada to a federal price on greenhouse gas emissions unless a province or territory has implemented a compliant carbon pricing regime. Litigation concerning the act is ongoing, and it is unclear how the act will ultimately treat provincial plans. In Alberta, large industrial emitters are subject to the Carbon Competitiveness Incentive Regulation (CCIR). The CCIR prices carbon, but provides cost protection to emission-intensive / trade-exposed industries, including Devon’s oil sands operations. The impact to our operations from these laws and regulations is expected to be minimal in the near term. Oil and gas facilities that are not subject to the CCIR are exempt from its economy-wide carbon levy until 2023.

In addition to regulatory risk, other market and social initiatives resulting from the changing perception of climate change present risks for our business. For example, in an effort to promote a lower-carbon economy, there are various public and private initiatives subsidizing the development of alternative energy sources, including by mandating the use of specific fuels or technologies. These initiatives may reduce the competitiveness of carbon-based fuels, such as oil and gas. Moreover, certain financial institutions, funds and other sources of capital have begun restricting or eliminating their investment in oil and natural gas activities due to their concern regarding climate change. Such restrictions in capital could make it more difficult to secure funding to operate our business. Finally, governmental entities and other plaintiffs have brought, and may continue to bring, claims against us and other oil and gas companies for purported damages caused by the alleged effects of climate change. These and the other regulatory, social and market risks relating to climate change described above could result in unexpected costs, increase our operating expense and reduce the demand for our products, which in turn could lower the value of our reserves and have a material adverse effect on our profitability, financial condition and liquidity.  

Our Hedging Activities Limit Participation in Commodity Price Increases and Involve Other Risks

We enter into financial derivative instruments with respect to a portion of our production to manage our exposure to oil, gas and NGL price volatility. To the extent that we engage in price risk management activities to protect ourselves from commodity price declines, we will be prevented from fully realizing the benefits of commodity price increases above the prices established by our hedging contracts. In addition, our hedging arrangements may expose us to the risk of financial loss in certain circumstances, including instances in which the contract counterparties fail to perform under the contracts. Moreover, as a result of the Dodd-Frank Wall Street Reform and Consumer Protection Act and other legislation, hedging transactions and many of our contract counterparties have become subject to increased governmental oversight and regulations in recent years. Although we cannot predict the ultimate impact of these laws and the related rulemaking, some of which is ongoing, existing or future regulations may adversely affect the cost

18


Table of Contents

 

Index to Financial Statements

and availability of our hedging arrangements, including by causing our contract counterparties, which are generally financial institutions and other market participants, to curtail or cease their derivatives activities.