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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)

For the fiscal year ended December 31, 20152018

or

Commission File Number 001-32318

DEVON ENERGY CORPORATION

(Exact name of registrant as specified in its charter)

Registrant’s telephone number, including area code:

(405) 235-3611

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

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

None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  x☒     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  x☒

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

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

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

Large accelerated filerx            Accelerated filer¨            Non-accelerated filer¨

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  x☒

The aggregate market value of the voting common stock held by non-affiliates of the registrant as of June 30, 201529, 2018 was approximately $24.3$22.5 billion, based upon the closing price of $59.49$43.96 per share as reported by the New York Stock Exchange on such date. On February 10, 2016, 441.36, 2019, 438.3 million shares of common stock were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of Registrant’s definitive Proxy statement for the 2016Statement 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.

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DEVON ENERGY CORPORATION

FORM 10-K

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DEFINITIONS

Unless the context otherwise indicates, references to “us,” “we,” “our,” “ours,” “Devon”“Devon,” the “Company” and the “Company”“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.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.

“DOE” means Department of Energy.

“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.,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.EnLink, and, unless the context otherwise indicates, EnLink Midstream Manager, LLC, the managing member of EnLink Midstream, LLC.

“GeoSouthern” means GeoSouthern Energy Corporation.

“Inside FERC” refers to the publicationInside 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.

“MBbls” means thousand barrels.

“MBoe” means thousand Boe.

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“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.

“Pre-tax 10% present value”OPIS” means the present valueOil Price Information Service.

“PHMSA” means United States Department of Devon’s pre-tax future net revenue to be generated from the production of proved reserves, net of estimated productionTransportation Pipeline and development costs and site restoration and abandonment charges.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”Tax Reform Legislation” means Tall Oak Midstream, LLC.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.

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

“WTI” means West Texas Intermediate.

“/Bbl” means per barrel.

“/d” means per day.

“/MMBtu” means per MMBtu.

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INFORMATION REGARDING FORWARD-LOOKING STATEMENTS

This report includes “forward-looking statements” as defined by the SEC. Such statements areinclude 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. Such forward-lookingAll statements, are based on our examinationother than statements of historical operating trends,facts, included in this report that address activities, events or developments that Devon expects, believes or anticipates will or may occur in the information used to prepare our December 31, 2015 reserve reports and other data in our possession or available from third parties.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:

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 and publicly held since 1988, Devon (NYSE: DVN) is a leadingan 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. Our portfolio of oil and gas properties provides stable, environmentally responsible production and a platform for future growth. We have doubled our onshore North American oil production since 2010 to more than 275 MBbls per day and have a deep inventory of development opportunities. Devon also produces over 1.6 Bcf of natural gas a day and more than 136 MBbls of NGLs per day.

Additionally,In July 2018, we control EnLink, a leading integratedexited the midstream business with significant sizeby divesting our aggregate ownership interests in EnLink and scale in key operating regions in the U.S. This MLP focuses on providing gathering, transmission, processing, fractionation and marketing to producers of natural gas, NGLs, crude oil and condensate.General Partner.

A Delaware corporation formed in 1971, we have been publicly held since 1988, and our common stock is listed on the NYSE. Our principal and administrative offices are located at 333 West Sheridan, Oklahoma City, OK 73102-5015 (telephone 405-235-3611). As of December 31, 2015,2018, Devon and its consolidated subsidiaries had approximately 6,6002,900 employees. Approximately 1,400 of such 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, http://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 (includingdocuments available on our website include our Code of Ethics for the Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer).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.

Strategywww.sec.gov.

Our primary goalStrategy

Our business strategy is to build value per debt-adjusted share by:

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.

During 2015, we continued to execute on this strategy and experienced a number of key achievements that are outlined in this report. However, we, and the entire upstream energy sector, have faced both operationalsheet, as well as adequate liquidity and financial challenges as oil and natural gas prices weakened significantly throughout 2015 and continued into 2016. To navigate these turbulent times, we are using our focused strategy, flexible portfolio of assets and leadership experience to execute on a number of initiatives that will ensure our long-term financial strength.

Specifically, after completing the STACK acquisition discussedflexibility, in this report, we had approximately $3.9 billion of liquidity.

While we will continueorder to operate and developcompetitively 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 premier portfolio of assets, we are committed tocore operations, protecting our balance sheetinvestment-grade credit ratings, and managingpaying and growing our capital programsshareholder dividend.

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During 2018, we reduced our cash inflows, including Access Pipeline proceeds.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 we are significantly reducingof our capital investment in responseplanned dispositions, our Board of Directors has increased our share repurchase program to lower commodity prices. We plan to invest $900 million to $1.1$5 billion in our upstream programs, a decrease of roughly 75% compared to our 2015 capital. We are also committed to reducing our G&AFebruary 2019 and field-level operating costs commensurate with our reduced, but focused, activity level. Following a number of cost-reduction initiatives culminating with our February 2016 workforce reduction, we are expecting a $700 million to $900 million reduction in operating and G&A costs on an annualized basis.

Also, in February 2016, we reducedraised our quarterly common stock dividend 75%12.5% to $0.06$0.09 per share.

Oil and Gas Properties

Property Profiles

The locations of our core oil and gas properties are presented on the following map. Additional information related to these properties follows this map, as well as information describing EnLink’s assets.

The following table outlines aKey summary of key data infrom each of our operating areas of operation as of and for the year ended December 31, 2015. 2018 are detailed in the map below. Notes 2022 and 2123 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.

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Delaware Basin – The Delaware Basin has been a legacy asset for Devonis 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, Delaware, Wolfcamp and Leonard formations. TheseWe expect these oil and liquids-rich opportunities across our acreage in the Delaware Basin will offerto deliver high-margin growth potential 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 2016,2019, we plan to invest approximately $200$900 million of capital in the Delaware Basin, primarily focused onmaking it the second Bone Spring opportunitytop-funded asset in the basin of southeast New Mexico.portfolio.

STACK – In early January 2016, we increased our acreage in the Woodford Shale and Meramec plays by acquiring 80,000 net acres in the STACK. The STACK development, located primarily in Oklahoma’s Canadian, Kingfisher and Blaine counties, is named for the stacked pay in the area.one of Devon’s top assets. Our Woodford ShaleSTACK position is the largest and one of the bestlargest in the industry. Recent well-completion design enhancements have resulted in greater productivity and improved economics. Earlyindustry, providing visible long-term stable production. At December 31, 2018, we had five operated rigs with drilling activityfocused in the Meramec play has been encouraging across our core position in the oil and liquids window.formation. In 2016,2019, we plan approximately $325$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 early 2014 from GeoSouthern and have approximately 66,000 net acres located in the DeWitt and Lavaca counties in south Texas.2014. Since acquiring these assets, we have delivered tremendous results increasing production by 125%.producing 173 million oil-equivalent barrels. Our excellent results are driven byourby our development in DeWitt County, which is located in the economic core of the play. In 2016, we expect ourOur Eagle Ford assets to once again deliver the highest operating margin of any assetgenerated significant cash flow in the portfolio and2018. In 2019, we plan approximately $200$300 million of capital investment.

Rockies Oil– Our operations areacreage in the Rockies is focused on emerging oil opportunities in the Powder River Basin and the Wind River Basin. In the Powder River, we are currently targeting several Cretaceous oil objectives, including the Turner, Parkman and Frontier formations. Recent drilling success in these formationsthis 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. InAs of December 2015,31, 2018, we acquired 253,000 net acreshad two operated rigs targeting the Turner, Parkman, Teapot and Niobrara formations in the “core”northern Converse County of the oil fairway in the Powder River. This acquisition delivers some of the best returns in our portfolio and is a significant resource opportunity.River Basin. In 2016,2019, we plan approximately $75$300 million of capital investment.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, aan 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. In 2014, we brought the third phaseThe Jackfish operation consists of Jackfish into operation, which ramped up to facility capacity by

the third quarter of 2015.three facilities. We expect each phaseJackfish to maintain a reasonably flat production profile for greater than 2015 years at an average gross production raterequiring approximately $200 million of approximately 35 MBbls per day at each facility.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, 2015. With our 50% partner,2018. Currently, we are evaluating our development timelinehave minimal planned capital outlays for Pike.

To facilitatePike in the deliverynear future. The majority of our heavy oil production, we have a 50% interest in the Access Pipeline transportation system in Canada. This pipeline system allows us to blend our heavy oil production with condensate or other blend-stockPike leasehold does not expire until 2025 and transport the combined product to the Edmonton area for sale. The Access Pipeline system has the capacity to transport approximately 170 MBbls of bitumen blend per day, net to our 50% interest. As discussed in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this report, we have plans to monetize our interest in Access Pipeline in 2016. With any buyer of Access Pipeline, we will also enter into a contractual arrangement to continue transporting our heavy oil volumes on Access Pipeline.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 high margin oil development play that produces heavy oil by conventional means, without the need for steam injection.

In 2016,2019, we plan approximately $175 million of capital investmentto separate our operations in our Canadian Heavy Oil business.Canada.

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 commodity price environment in 2015, we shifted focus to enhancing existing well performance through re-fracturing, artificial lift and line pressure reduction projects. In 2015, we accelerated our horizontal refrac program to test the re-stimulation of 25 wells and also had an active vertical refrac program, re-stimulating 140 vertical wells. In 2016,2019, we plan on minimal refrac activity in the Barnett.to separate our Barnett Shale assets.

Other– Other assets are located primarily in the Midland Basin, east Texas, Granite Wash and Mississippian-Lime areas. Substantially all of these properties have been identified for divestiture in 2016.

Proved Reserves

For estimates of our proved developed and proved undeveloped reserves and the discussion of the contribution by each key property, see Note 2123 in “Item 8. Financial Statements and Supplementary Data” of this report.

Since the beginning of 2015, no estimates of our proved reserves have been filed with or included in reports to any federal or foreign governmental authority or agency except in filings with the SEC and the DOE. Reserve estimates filed with the SEC correspond with the estimates of our reserves contained in this report. Reserve estimates filed with the DOE are based upon the same underlying technical and economic assumptions as the estimates of our reserves included in this report. However, the DOE requires reports to include the interests of all owners in wells that we operate and to exclude all interests in wells that we do not operate.

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.

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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, (“Qualified 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 Group’s Director and key members of the Group have appropriate technical qualifications to oversee the preparation of reserves estimates, including any or allestimates. The Group reports to and is managed through our finance department. No portion of the following:Group’s compensation is directly dependent on the quantity of reserves booked.

The current Director of the Group has allover 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 qualifications listed above. The current Director has been involved with reserves estimation in accordance with SEC definitionsSociety of Petroleum Engineers and guidance since 1987. He has 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.  He has been employed by Devon for the past fifteen years, including the past eight in his current position. During his career, he has been responsible for reserves estimation as the primary reservoir engineer for projects including, but not limited to:

From 2003 to 2010, he served as the reservoir engineering representative on our internal peer review team. In this role, he reviewed reserves and resource estimates for projects including, but not limited to, the Mobile Bay Norphlet Discoveries (Gulf of Mexico Shelf), Cascade Lower Tertiary Development (Gulf of Mexico Deepwater) and Polvo Development (Campos Basin, Brazil).

The Group reports independently of any of our operating divisions and currently is in our Chief Financial Officer’s organization. No portion of the Group’s compensation is directly dependent on the quantity of reserves booked.

Throughout the year, the Group performs internal reserves auditsreviews of each operating division’scountry’s reserves. Selection criteria of reserves that are audited include major fields and major additions and revisions to reserves. In addition, the Group reviews reserve estimates with each of the third-party petroleum consultants discussed below. The Group also ensures our Qualified Estimators obtain continuing education related to the fundamentals of SEC proved reserves assignments.

The Group also oversees audits and reserves estimates performed by qualified third-party petroleum consulting firms. During 2015,2018, we engaged two such firms to audit 95%approximately 89% of our proved reserves. LaRoche Petroleum Consultants, Ltd. audited 94% of our 2015 U.S. reserves and Deloitte LLP audited 96% of our Canadian reserves.

“Audited” reserves are those quantities of reserves that were estimated by our employees and audited by an independent petroleum consultant. The Society of Petroleum Engineers’ definition of an audit is an examination of a company’s proved oil and gas reserves and net cash flow by an independent petroleum consultant that is conducted for the purpose of expressing an opinion as to whether such estimates, in aggregate, are reasonable and have been estimated and presented in conformityaccordance 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 Reserves Committee assists the Board of Directors with its duties and responsibilities in evaluating and reporting our proved reserves, much like our Audit Committee assists the Board of Directors in supervising our audit and financial reporting requirements. Besides being independent, 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 responsibilities of the Reserves Committee include the following:

The following table presents our estimated pre-tax cash flow information related to our proved reserves. These estimates correspond with the method used in presenting the “Supplemental Information on Oil and Gas Operations” in Note 21 to our consolidated financial statements included in this report.

Pre-tax future net revenue and pre-tax 10% present value are non-GAAP measures. The standardized measure was $6.7 billion at the end of 2015. Included as part of the standardized measure were discounted future income taxes of $0.3 billion. Excluding these taxes, the pre-tax 10% present value was $7.0 billion. We believe the pre-tax 10% present value is a useful measure in addition to the after-tax standardized

measure. The pre-tax 10% present value assists in both the estimation of future cash flows of the current reserves as well as in making relative value comparisons among peer companies. The after-tax standardized measure is dependent on the unique tax situation of each individual company, while the pre-tax 10% present value is based on prices and discount factors, which are more consistent from company to company.

Production, Production Prices and Production Costs

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

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Drilling Statistics

The following table summarizes our development and exploratory drilling results.

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The following table presents the wells that were in progress on December 31, 2015.2018. As of February 1, 2016,2019, these wells were still in progress.

Productive Wells

The following table sets forth our producing wells as of December 31, 2015.2018.

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 19,00012,900 gross wells. As operator, we receive reimbursement for direct expenses incurred to perform our duties, as well as monthly per-well producing, drilling, and drillingconstruction 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, 2015.2018. Of our 5.53.8 million net acres, approximately 3.01.9 million acres are held by production. The acreage in the table includes 0.2 million, 0.40.1 million and 0.1 million net acres subject to leases that are scheduled to expire during 2016, 20172019, 2020 and 2018,2021, respectively. As of December 31, 2015,2018, there were no proved undeveloped reserves associated with our expiring acreage. Of the 0.70.3 million net acres set to expire by December 31, 2018,2021, we will performanticipate 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 2015,2018, we allowed approximately 0.80.1 million acres to expire.