10-K 1 dvn-10k_20161231.htm DVN-10K-20161231 dvn-10k_20161231.htm

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, 2016

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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes      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, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

 

Large accelerated filer

 

Accelerated filer

 

Non-accelerated filer

 

Smaller reporting company

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 30, 2016 was approximately $18.9 billion, based upon the closing price of $36.25 per share as reported by the New York Stock Exchange on such date. On February 8, 2017, 524.6 million shares of common stock were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Proxy statement for the 2017 annual meeting of stockholders – Part III

 

 

 

 

 


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DEVON ENERGY CORPORATION

FORM 10-K

TABLE OF CONTENTS

 

PART I

 

6

 

 

 

Items 1 and 2. Business and Properties

 

6

Item 1A.  Risk Factors

 

17

Item 1B.  Unresolved Staff Comments

 

24

Item 3.     Legal Proceedings

 

25

Item 4.     Mine Safety Disclosures

 

25

 

 

 

PART II

 

26

 

 

 

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

 

26

Item 6.     Selected Financial Data

 

28

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

 

29

Item 7A.  Quantitative and Qualitative Disclosures about Market Risk

 

54

Item 8.     Financial Statements and Supplementary Data

 

56

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

 

123

Item 9A.  Controls and Procedures

 

123

Item 9B.  Other Information

 

123

 

 

 

PART III

 

124

 

 

 

Item 10.   Directors, Executive Officers and Corporate Governance

 

124

Item 11.   Executive Compensation

 

124

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

 

124

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

 

124

Item 14.   Principal Accountant Fees and Services

 

124

 

 

 

PART IV

 

125

 

 

 

Item 15.   Exhibits and Financial Statement Schedules

 

125

Signatures

 

133

 

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DEFINITIONS

Unless the context otherwise indicates, references to “us,” “we,” “our,” “ours,” “Devon” and the “Company” refer to Devon Energy Corporation and its consolidated subsidiaries. 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.

“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.

“Coronado” means Coronado Midstream Holdings LLC.

“Crosstex” means Crosstex Energy, Inc. together with Crosstex Energy L.P.

“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.

“E2” means E2 Energy Services, LLC together with E2 Appalachian Compression, LLC.

“EMH” means EnLink Midstream Holdings, LP.

“EnLink” means EnLink Midstream Partners, L.P., 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.

“GeoSouthern” means GeoSouthern Energy Corporation.

“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.

“LPC” means LPC Crude Oil Marketing LLC.

“Matador” means MRC Energy Company.

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“MBbls” means thousand barrels.

“MBoe” means thousand Boe.

“Mcf” means thousand cubic feet.

“MLP” means master limited partnership.

“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.

“Senior Credit Facility” means Devon’s syndicated unsecured revolving line of credit.

“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.

“Tall Oak” means Tall Oak Midstream, LLC.

“TSR” means total shareholder return.

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

“VEX” means Victoria Express Pipeline and related truck terminal and storage assets.

“WTI” means West Texas Intermediate.

“/d” means per day.

“/gal” means per gallon.


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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 “expects,” “believes,” “will,” “would,” “could,” “forecasts,” “projections,” “estimates,” “plans,” “expectations,” “targets,” “opportunities,” “potential,” “anticipates,” “outlook” and other similar terminology. Such forward-looking statements are based on our examination of historical operating trends, the information used to prepare our December 31, 2016 reserve reports and other data in our possession or available from third parties. 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 exploration and development activities;

 

risks related to our hedging activities;

 

counterparty credit risks;

 

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

 

risks relating to our indebtedness;

 

our ability to successfully complete mergers, acquisitions and divestitures;

 

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

 

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

 

midstream capacity constraints and potential interruptions in production;

 

competition for leases, materials, people and capital;

 

cyberattacks targeting our systems and infrastructure; 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.

 

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PART I

Items 1 and 2. Business and Properties

General

A Delaware corporation formed in 1971, Devon 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. Additionally, we control EnLink, a publicly–traded MLP with an integrated midstream business with significant size and scale in key operating regions in the U.S. For additional information regarding our control of, and ownership interest in, EnLink and its indirect general partner, the General Partner, see Note 2 in “Item 8. Financial Statements and Supplementary Data” of this report.

Devon has been publicly held since 1988, and our common stock is listed on the NYSE under the ticker symbol DVN. Our principal and administrative offices are located at 333 West Sheridan, Oklahoma City, OK 73102-5015 (telephone 405-235-3611). As of December 31, 2016, Devon and its consolidated subsidiaries had approximately 5,000 employees, of which approximately 1,500 employees are employed by EnLink (through its subsidiaries).

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.

In addition, the public may read and copy any materials Devon files with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington D.C. 20549. The public may also obtain information about the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Reports filed with the SEC are also made available on its website at www.sec.gov.

Devon Strategy

Devon is committed to delivering consistent top-quartile shareholder return among its peer group through a highly engaged culture focused on innovation, safety, operational excellence, environmental stewardship and social responsibility. We also maintain a strong commitment to financial strength and flexibility through all commodity price cycles, as reflected in the company’s investment grade credit ratings. We focus our business on building value per share by:

 

managing a premier asset portfolio;

 

delivering top-tier results within the areas that we operate;

 

continuing disciplined capital allocation; and

 

maintaining significant financial strength.

Our formidable portfolio of exploration and production assets and operations provides stable, environmentally responsible production and a platform for future growth. For Devon, 2016 was a transformational year as we executed our strategy. We successfully reshaped our asset portfolio with non-core divestitures and the continued development of our world-class operations in the STACK and Delaware Basin. These assets provide us with a sustainable, multi-decade growth platform that continues to improve in response to our successful drilling programs. During 2016, we delivered the best well productivity in Devon’s 45-year history and continued a four-year streak of increasing Devon’s initial 90-day production rates. Devon has more than doubled its onshore North American oil

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production since 2011 and has a deep inventory of development opportunities to deliver future oil growth. Adding to these operational highlights, we had several key actions in 2016 as discussed below.

 

Raised net proceeds of $1.5 billion in an offering of our common stock

 

Reduced exploratory and development capital investment by $2.8 billion, or 65%

 

Reduced G&A and field operating costs by $845 million, or 25%

 

Reduced our dividend $175 million, or 44%

 

Successfully divested certain non-core upstream assets in the U.S. and our 50% interest in the Access Pipeline in Canada for approximately $3.1 billion

 

Reduced Devon’s debt by $3.1 billion, or 31%, and have no significant long term maturities until July 2021

 

Completed a strategic bolt-on acquisition in the STACK for $1.5 billion

 

Exited 2016 with approximately $5 billion in liquidity  

As we enter 2017 and continue to look toward the future, we will approach the current environment in a manner that drives efficiencies across our portfolio. We will manage activity levels within our cash flow by achieving additional operating cost savings and increasing capital productivity, while remaining committed to allocating capital in a disciplined manner that is driven by both value and return. We believe we capture the full value of our assets and improve returns through maximizing our base production and optimizing our capital program. The activities that support this strategy include minimizing controllable downtime, enhancing well productivity, ensuring disciplined project execution, performing premier technical work, focusing on developmental drilling and reducing our operating and capital costs.

EnLink Strategy

EnLink focuses on providing gathering, transmission, processing, storage, fractionation and marketing to upstream oil and natural gas producers, including Devon.  

EnLink connects the wells of natural gas producers in its market areas to its gathering systems, processes natural gas for the removal of NGLs, fractionates NGLs into purity products and markets those products for a fee, transports natural gas and ultimately provides natural gas to a variety of markets. Furthermore, EnLink purchases natural gas from natural gas producers and other supply sources and sells that natural gas to utilities, industrial consumers, other marketers and pipelines.

EnLink’s primary business objective is to provide cash flow stability, while growing through prudent and profitable investments. EnLink accomplishes its objectives through long-term, fee-based contracts and maintaining a strong financial position through a conservative and balanced capital structure highlighted by its investment grade status. EnLink has consistently demonstrated expertise within the MLP space and continues to employ a proven business model that includes growing, expanding and executing on its strategy within top basins where Devon and other successful upstream producers operate.  

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Oil and Gas Properties

Property Profiles

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The following table outlines a summary of key data in each of our operating areas as of and for the year ended December 31, 2016. Notes 21 and 22 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.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proved Reserves

 

 

Production

 

 

 

 

 

 

MMBoe

 

 

% of Total

 

 

% Liquids

 

 

MBoe/d

 

 

% of Total

 

 

% Liquids

 

 

Gross Wells Drilled

 

Barnett Shale

 

895

 

 

 

44

%

 

 

25

%

 

 

169

 

 

 

28

%

 

 

27

%

 

 

 

Delaware Basin

 

108

 

 

 

5

%

 

 

75

%

 

 

60

 

 

 

10

%

 

 

74

%

 

 

58

 

Eagle Ford

 

75

 

 

 

4

%

 

 

76

%

 

 

76

 

 

 

12

%

 

 

76

%

 

 

63

 

Heavy Oil

 

504

 

 

 

24

%

 

 

99

%

 

 

134

 

 

 

22

%

 

 

98

%

 

 

25

 

Rockies Oil

 

24

 

 

 

1

%

 

 

64

%

 

 

19

 

 

 

3

%

 

 

79

%

 

 

19

 

STACK

 

393

 

 

 

19

%

 

 

47

%

 

 

93

 

 

 

15

%

 

 

48

%

 

 

133

 

Other

 

59

 

 

 

3

%

 

 

90

%

 

 

17

 

 

 

3

%

 

 

81

%

 

 

28

 

Retained assets

 

2,058

 

 

 

100

%

 

 

54

%

 

 

568

 

 

 

93

%

 

 

62

%

 

 

326

 

Divested assets (1)

 

 

 

 

 

 

 

 

 

 

43

 

 

 

7

%

 

 

51

%

 

 

14

 

Total

 

2,058

 

 

 

100

%

 

 

54

%

 

 

611

 

 

 

100

%

 

 

61

%

 

 

340

 

 

(1)

As of December 31, 2016, these assets had been divested and therefore had no associated reserves.

Led by results from the STACK, Delaware Basin and Eagle Ford, Devon achieved the best drilling results in our 45-year history. Our initial 90-day production rates in 2016 increased for the fourth consecutive year, advancing more than 300% from 2012 levels. These productivity improvements were driven by activity focused in top resource plays, improved subsurface reservoir characterization, leading-edge completion designs and improvements in lateral placement. Excluding the effects of divestitures, our drilling results increased our proved reserves in 2016 on a retained asset basis by 3%. The most significant reserves growth came from our U.S. operations, where we replaced approximately 175% of our 2016 production.

Barnett Shale – This is our largest property in terms of production and proved reserves. Our leases are located primarily in Denton, Johnson, 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. Given the sustained low gas price environment, we continue to focus on enhancing existing well performance through re-fracturing, artificial lift and line pressure reduction projects. In 2017, we plan on minimal development activity, with planned capital investment of up to $50 million to optimize base production and further de-risk future development activity.

Delaware Basin – The Delaware Basin is one of Devon’s top-two franchise assets and continues to offer exploration and low-risk development opportunities from many geologic reservoirs and play types, including the oil-rich Bone Spring, Delaware, Wolfcamp and Leonard formations. These oil and liquids-rich opportunities across our acreage in the Delaware Basin will offer high-margin growth for many years to come. At December 31, 2016, we had three operated rigs. In 2017, we plan to invest approximately $700 million of capital in the Delaware Basin and steadily ramp up activity with as many as 10 operated rigs running by the end of the year, primarily focused on the Bone Spring, Leonard and Wolfcamp formations.

Eagle Ford – We acquired our position in the Eagle Ford in 2014 from GeoSouthern and have approximately 66,000 net acres located in DeWitt and Lavaca counties in south Texas. Since acquiring these assets, we have delivered tremendous results by producing 94 million oil-equivalent barrels. Our excellent results are driven by our development in DeWitt County, located in the economic core of the play. With the highest margins in our portfolio, our Eagle Ford assets generated approximately $550 million of direct cash margin in 2016. In 2017, we plan approximately $175 million of capital investment.

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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. In 2014, we brought the third phase of Jackfish into operation, which ramped up to facility capacity by the third quarter of 2015. At $55/Bbl WTI, direct cash margin from our Heavy Oil assets has the potential to approach $800 million in 2017. We expect Jackfish to maintain a reasonably flat production profile for greater than 20 years requiring only 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, 2016. With our 50% partner, we continue to evaluate our development timeline for Pike.

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, high margin oil development play that produces heavy oil by conventional means, without the need for steam injection.

In 2017, we plan approximately $300 million of capital investment in our Canadian Heavy Oil business.

Rockies Oil – Our acreage in the Rockies includes approximately 470,000 net surface acres, focused on emerging oil opportunities in the Powder River Basin and the Wind River Basin. Recent drilling success in these formations has expanded our drilling inventory, and we expect further growth as we continue to de-risk this emerging light-oil opportunity. As of December 31, 2016, we had one operated rig targeting the Parkman, Teapot and Turner formations within the Cretaceous oil objectives of the Powder River Basin. In 2017, we plan approximately $175 million of capital investment.

STACK – The STACK development, located primarily in Oklahoma’s Canadian, Kingfisher and Blaine counties, is one of Devon’s top-two franchise assets. Devon has two primary fields in the area: the Woodford Shale and the Meramec. In 2016, we increased our acreage in these positions by acquiring 80,000 net acres in the STACK. Our acreage in the play now includes approximately 430,000 net acres. Our STACK position is the largest and one of the best in the industry, providing visible long-term growth. Recent well-completion design enhancements have resulted in greater productivity and improved economics. Early drilling activity in the Meramec play has produced record setting results across our core position in the oil and liquids window. At December 31, 2016, we had six operated rigs with drilling focused in the Meramec formation. In 2017, we plan approximately $750 million of capital investment and expect to continue to increase drilling activity throughout 2017 and run up to 10 operated rigs by the end of the year.

Proved Reserves

For estimates of our proved developed and proved undeveloped reserves and the discussion of the contribution by each property, see Note 22 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.

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,

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(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 approximately 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 16 years, including the past nine 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 audits of each operating division’s reserves. The Group also oversees audits and reserves estimates performed by qualified third-party petroleum consulting firms. During 2016, we engaged two such firms to audit 89% of our proved reserves in accordance with generally accepted petroleum engineering and evaluation methods and procedures. LaRoche Petroleum Consultants, Ltd. audited 86% of our 2016 U.S. reserves, and Deloitte LLP audited 96% of our Canadian reserves.

In addition to conducting these internal 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 also 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)

 

2016

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Barnett Shale

 

 

 

 

 

 

 

 

265

 

 

 

15

 

 

 

60

 

Jackfish

 

 

 

 

 

40

 

 

 

 

 

 

 

 

 

40

 

U.S.

 

 

47

 

 

 

 

 

 

510

 

 

 

42

 

 

 

174

 

Canada

 

 

8

 

 

 

40

 

 

 

7

 

 

 

 

 

 

49

 

Total North America

 

 

55

 

 

 

40

 

 

 

517

 

 

 

42

 

 

 

223

 

2015

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Barnett Shale

 

 

 

 

 

 

 

 

291

 

 

 

17

 

 

 

66

 

Jackfish

 

 

 

 

 

31

 

 

 

 

 

 

 

 

 

31

 

U.S.

 

 

60

 

 

 

 

 

 

579

 

 

 

50

 

 

 

206

 

Canada

 

 

10

 

 

 

31

 

 

 

8

 

 

 

 

 

 

42

 

Total North America

 

 

70

 

 

 

31

 

 

 

587

 

 

 

50

 

 

 

248

 

2014

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Barnett Shale

 

 

1

 

 

 

 

 

 

332

 

 

 

20

 

 

 

76

 

Jackfish

 

 

 

 

 

20

 

 

 

 

 

 

 

 

 

20

 

U.S.

 

 

48

 

 

 

 

 

 

660

 

 

 

50

 

 

 

207

 

Canada

 

 

10

 

 

 

20

 

 

 

41

 

 

 

1

 

 

 

39

 

Total North America

 

 

58

 

 

 

20

 

 

 

701

 

 

 

51

 

 

 

246

 

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Table of Contents

 

Index to Financial Statements

 

 

 

Average Sales Price

 

 

 

 

 

Year Ended December 31,

 

Oil (Per Bbl)

 

 

Bitumen (Per Bbl)

 

 

Gas (Per Mcf)

 

 

NGLs (Per Bbl)

 

 

Production Cost (Per Boe) (1)

 

2016

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Barnett Shale

 

$

41.03

 

 

$

 

 

$

1.76

 

 

$

10.31

 

 

$

6.16

 

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

 

2015

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Barnett Shale

 

$

46.47

 

 

$

 

 

$

2.00

 

 

$

9.62

 

 

$

6.02

 

Jackfish

 

$

 

 

$

23.41

 

 

$

 

 

$

 

 

$

12.43

 

U.S.

 

$

44.01

 

 

$

 

 

$

2.17

 

 

$

9.32

 

 

$

7.52

 

Canada

 

$

30.58

 

 

$

23.41

 

 

 

N/M

 

 

$

 

 

$

13.18

 

Total North America

 

$

42.12

 

 

$

23.41

 

 

$

2.14

 

 

$

9.32

 

 

$

8.48

 

2014

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Barnett Shale

 

$

95.51

 

 

$

 

 

$

3.78

 

 

$

21.98

 

 

$

5.25

 

Jackfish

 

$

 

 

$

55.88

 

 

$

 

 

$

 

 

$

20.59

 

U.S.

 

$

85.64

 

 

$

 

 

$

3.92

 

 

$

24.46

 

 

$

7.52

 

Canada

 

$

68.14

 

 

$

55.88

 

 

$

3.64

 

 

$

50.52

 

 

$

20.10

 

Total North America

 

$

82.47

 

 

$

55.88

 

 

$

3.90

 

 

$

24.89

 

 

$

9.49

 

 

(1)

Represents LOE per Boe and excludes severance and property taxes. Jackfish and Canada costs include purchases of natural gas used to heat the heavy oil reservoirs. The natural gas is generally 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

 

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

 

2015

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

U.S.

 

 

298.6

 

 

 

1.8

 

 

 

40.7

 

 

 

 

 

 

339.3

 

 

 

1.8

 

 

 

341.1

 

Canada

 

 

79.0

 

 

 

 

 

 

 

 

 

 

 

 

79.0

 

 

 

 

 

 

79.0

 

Total North America

 

 

377.6

 

 

 

1.8

 

 

 

40.7

 

 

 

 

 

 

418.3

 

 

 

1.8

 

 

 

420.1

 

2014

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

U.S.

 

 

474.4

 

 

 

0.4

 

 

 

5.0

 

 

 

1.2

 

 

 

479.4

 

 

 

1.6

 

 

 

481.0

 

Canada

 

 

190.8

 

 

 

1.0

 

 

 

 

 

 

0.5

 

 

 

190.8

 

 

 

1.5

 

 

 

192.3

 

Total North America

 

 

665.2

 

 

 

1.4

 

 

 

5.0

 

 

 

1.7

 

 

 

670.2

 

 

 

3.1

 

 

 

673.3

 

 

(1)

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

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The following table presents the wells that were in progress on December 31, 2016. As of February 1, 2017, these wells were still in progress.

 

 

 

Gross (1)

 

 

Net (2)

 

U.S.

 

 

42.0

 

 

 

14.5

 

Canada

 

 

10.0

 

 

 

10.0

 

Total North America

 

 

52.0

 

 

 

24.5

 

 

(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, 2016.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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.

 

 

9,710

 

 

 

3,499

 

 

 

10,061

 

 

 

7,577

 

 

 

19,771

 

 

 

11,076

 

Canada

 

 

3,239

 

 

 

3,138

 

 

 

644

 

 

 

456

 

 

 

3,883

 

 

 

3,594

 

Total North America

 

 

12,949

 

 

 

6,637

 

 

 

10,705

 

 

 

8,033

 

 

 

23,654

 

 

 

14,670

 

 

(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 822 and 404 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 15,200 gross wells. As operator, we receive reimbursement for direct expenses incurred to perform our duties, as well as monthly per-well producing and drilling 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.

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Acreage Statistics

The following table sets forth our developed and undeveloped lease and mineral acreage as of December 31, 2016. Of our 4.6 million net acres, approximately 2.4 million acres are held by production. The acreage in the table includes 0.3 million, 0.2 million and 0.1 million net acres subject to leases that are scheduled to expire during 2017, 2018 and 2019, respectively. As of December 31, 2016, there were no proved undeveloped reserves associated with our expiring acreage. Of the 0.6 million net acres set to expire by December 31, 2019, we will perform 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 2016, we allowed approximately 0.3 million acres to expire, which is consistent with expirations in prior years.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Developed

 

 

Undeveloped

 

 

Total

 

 

 

Gross (1)

 

 

Net (2)

 

 

Gross (1)

 

 

Net (2)

 

 

Gross (1)

 

 

Net (2)

 

 

 

(Thousands)

 

U.S.

 

 

1,800

 

 

 

1,218

 

 

 

4,138

 

 

 

1,917

 

 

 

5,938

 

 

 

3,135

 

Canada

 

 

695

 

 

 

512

 

 

 

2,075

 

 

 

953

 

 

 

2,770

 

 

 

1,465

 

Total North America

 

 

2,495

 

 

 

1,730

 

 

 

6,213

 

 

 

2,870

 

 

 

8,708

 

 

 

4,600

 

 

(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.

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, other than a preliminary review of local records, little investigation of record title is made at the time of acquisitions of undeveloped properties. Title investigations, which generally include a review of title opinions of outside counsel, are made prior to the consummation of an acquisition of producing properties and before commencement of drilling operations on undeveloped properties.

EnLink Midstream Properties

EnLink represents the primary component of our midstream operations. EnLink’s assets are comprised of systems and other assets located in four primary regions:

 

Texas – The Texas assets consist of transmission pipelines with a capacity of approximately 920 MMcf/d, processing facilities with a total processing capacity of approximately 1.6 Bcf/d and gathering systems with total capacity of approximately 2.3 Bcf/d.

 

Oklahoma – The Oklahoma assets consist of processing facilities with a total processing capacity of approximately 795 MMcf/d and gathering systems with total capacity of approximately 810 MMcf/d.

 

Louisiana – The Louisiana assets consist of transmission pipelines with a capacity of approximately 3.5 Bcf/d, processing facilities with a total processing capacity of approximately 1.9 Bcf/d, gathering systems with total capacity of approximately 510 MMcf/d, 720 miles of liquids transport lines and four fractionation assets with total fractionation capacity of 175 MBbls/d.

 

Crude and Condensate – The Crude and Condensate assets consist of approximately 540 miles of crude oil and condensate pipelines with total capacity of approximately 116 MBbls/d, 900 MBbls of above ground storage and eight condensate stabilization and natural gas compression stations with combined capacities of approximately 36 MBbls/d of condensate stabilization and 780 MMcf/d of natural gas compression.

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Index to Financial Statements

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 2017, our production was sold under the following contract terms.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Short-Term

 

 

Long-Term

 

 

 

Variable

 

 

Fixed

 

 

Variable

 

 

Fixed

 

Oil and bitumen

 

 

65

%

 

 

 

 

 

35

%

 

 

 

Natural gas

 

 

54

%

 

 

4

%

 

 

42

%

 

 

 

NGLs

 

 

53

%

 

 

17

%

 

 

30

%

 

 

 

 

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, 2016, 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)

 

 

112

 

 

 

36

 

 

 

48

 

 

 

28

 

Natural gas (Bcf)

 

 

487

 

 

 

338

 

 

 

149

 

 

 

 

NGLs (MMBbls)

 

 

9

 

 

 

9

 

 

 

 

 

 

 

Total (MMBoe)

 

 

202

 

 

 

101

 

 

 

73

 

 

 

28

 

 

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 2016, 2015 and 2014, no purchaser accounted for over 10% of our consolidated sales revenue.

Competition

See “Item 1A. Risk Factors.”

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

15


Table of Contents

 

Index to Financial Statements

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 integration 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 been particularly active in recent years in evaluating and, in some cases, promulgating 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 are subject to frequent delays.

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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 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 for wells drilled after January 1, 2017 in the Modernized Royalty Framework, the calculation is based on a percentage of production net of allowed deductions.

Marketing in Canada

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

Environmental, Pipeline Safety and Occupational Regulations

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. 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; 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. We consider the costs of environmental protection and safety and health compliance 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.

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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, during the period from January 1, 2014 to December 31, 2016, NYMEX WTI oil prices ranged from a high of $107.26 per Bbl to a low of $26.21 per Bbl. Average daily prices for NYMEX Henry Hub gas ranged from a high of $6.15 per MMBtu to a low of $1.64 per MMBtu during the same period. Such volatility is likely to continue in the future due to numerous factors beyond our control, including, but not limited to:

 

supply of and demand for oil, gas and NGLs, including consumer demand in emerging markets, such as China;

 

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 and Africa;

 

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

 

regional pricing differentials;

 

differing quality of oil produced (i.e., sweet crude versus heavy or sour crude);

 

differing quality and 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;

 

the overall economic environment; and

 

governmental regulations and taxes.

In the second half of 2014, global energy commodity prices began a rapid and significant decline, which continued through 2015 and into 2016. This commodity price decline adversely affected our business and results of operations and led to substantial impairments to our oil and gas properties during 2015 and 2016. A sustained weakness or further deterioration in commodity prices could materially and adversely impact our business by resulting in, or exacerbating, the following effects:

 

reducing the amount of oil, 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 additional 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

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Index to Financial Statements

given reservoir may change substantially over time as a result of several factors, including additional development 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.

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.

Future Exploration and Drilling Results Are Uncertain and Involve Substantial Costs

Our exploration and development 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 drilling 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 and surface cratering;

 

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

 

issues with title or in receiving governmental permits or approvals;

 

lack of access to pipelines or other transportation methods;

 

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, and certain of these events, particularly equipment failures or accidents, could impact third parties, including persons living in proximity to our operations, our employees and employees of our contractors, leading to possible injuries, death or significant property damage.

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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 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. 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 at times in the future could affect, our operations. Regulatory 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. 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, income taxes and climate change, as discussed below.

Hydraulic Fracturing – The EPA and other federal agencies, including the BLM, have made proposals that would subject hydraulic fracturing to further regulation and could 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 June 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 December 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 and several states have already adopted and more states are considering adopting laws and/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 and/or hydraulic fracturing or are considering doing so. 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, through EnLink or otherwise, 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 March 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. 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. 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.

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Seismic Activity – Recent 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 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.

 

Potential 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. In past years, legislation has been proposed that would, if enacted into law, make significant changes to U.S. tax laws, including to certain key U.S. federal income tax provisions currently available to oil and gas companies. Such legislative changes have included, but not been limited to, (i) the repeal of the percentage d