2020 Annual Report

PREMIUM PROVES

77284.indd 1 3/10/21 2:25 PM Andrew Abbott Ahmed Abdullah Bobby Abernathy Renesha Abraham Susan Abrahams Gus Abrahamson Linda Abrego Turk Ackerman David Ackman Aron Acosta OUR EMPLOYEES Ed Acosta Linda Acosta Kelvin Acuna Gabby Adame Cheryl Adams Nelda Adams Stephen Adams Rhonda Addison Jeremy Adrian Mike Adrion Alicia Affat Amer Afi fi Kristina Agee Bobbie Aguilar Candy Aguilar Sergio Aguilar Amit Ahuja Blaine Akin Shane Akin Shanthi Akkisetty Melissa Albert Alex Albertoni Marisol Albino Wilson Jennifer Alcocer Mahdee Aleem Cesar Aleman Krista Aleman Leon Aleman Aaron Alexander Anthony Alexander Kerry-Ann Alexander Mark Alexander Patrick Alexander Enaaz Ali Kirk Ali Maha Ali Meshal Al-Khabbaz Amanda Allahar Raymond Allbee Jennifer Allen Scott Allison Evan Allred Richard Alonso Derek Alquist Carlos Alvarado Teuscher Kim Alvarado Raul Alvarado Dan Ambuehl Syed Amir Junior Andall Aaron Anderson Brian Anderson Charlie Anderson Jason Anderson Jeremy Anderson Jim Anderson Karen Anderson Katie Anderson Landon Anderson Rene Anderson Scott Anderson Derek Andreas Levi Andreas Frances Andreassen Tony Aner Tori Angus Fernanda Araujo John Archambault Ali Ardington Carlos Arevalo Hugo Arevalo Mario Arevalo Alex Argueta Erin Arkison Joshua Armentrout Craig Armstrong Cody Arnold Artie Arredondo Edgar Arreola Andrea Arrey Jared Arrey Eric Arsenault Jayanthi Arya Jill Ashcraft Bob Asher Chelsea Ashworth Joe Aston Darrell Atkins Haritha Atluri Lizz Atnafu Jason Aultman Richard Austin Daubie Autry Jon Avery Orlando Ayala Wale Ayoola Sanaa Azeez Shelly Babcock Benjamin Baccus Darla Baccus David Baccus Krishna Bachan Scott Backer Sean Bader Dewayne Baethge Krystina Baez Dominic Baeza Raul Baeza Colby Baggs Bryan Bahr Jared Baier Diane Bailey Dustin Bailey James Bailey John Bailey Michael Bailey Mike Bailey Steve Bailey Peter Bair Jamie Baird Andy Baker Kevin Baker Mike Baker Neal Baker Lorraine Baline Gloria Ballin Amaar Bangee Kyle Bangert Kristian Baptiste Linda Barberousse Rex Barbour Jared Barden Gary Barker Hannah Barker Tarra Barker Colin Barnes Kelley Barnett Aaron Baros Peter Barragan Jennifer Barrera Mitzi Barrera Loren Barrett German Barrientos Keith Bartenhagen Amanda Bartlett Blain Barton James Barwis Coby Bass Travis Bates Whittney Bates Mary Ann Batie Crystal Baxter Heather Bayless Kevin Beahan Natalie Beasley Italo Beckles Brock Begg Casey Beiland Larry Beiland Rene Bela Richard Belasquez Rachel Belk Chris Bell Heath Bell Dennis Bellows Taylor Bellows Cory Benes Gabbi Bennett Kristy Bennett Tana Bennett Gust Benninger Andrew Bentley Fernando Berdoza Bryce Berg Shane Berg Helen Berhane Vickie Bernal Ty Bernhard Caroline Bertuzzi Dmytro Bevzenko Georges Beyrouti Sandeep Bhakhri Mayur Bhakta Pravat Bhusal Justin Bickenbach Samantha Bickenbach Bennie Biery Sam Biffl e Nacole Biggers Justin Biggs Tammy Billington Albert Billman Ryan Bingham Aaron Bishop Kevin Black Mindy Black Greg Blackman Ben Blackwelder Zeco Blair Gerardo Blanco Sibyl Blankenship Sara Blatnick Justin Blau Stephanie Bleich Dana Blevins Danielle Blevins Tracy Blome Johnnie Blount Brian Bock Jon Bocox Ken Boedeker Jarrid Boehm Deanne Boelter Aaron Bofenkamp Ryan Bofenkamp Dave Bokor Jordan Boland Paul Boland Yash Bolisetty Wade Bolting Kylie Bolton Courtney Bone Wendy Bone Christy Bonetti Laramie Bonham Kent Boomhower Pallavi Boppana Vera Boren Simone Borg Chris Borjas Cody Bouler Tyson Bouler Laura Bourgeois Deidra Bourland Heather Bourland Kyle Bowen Ashley Bowman Kyle Bowzer Srinivas Boyapati John Boyd Jason Boykin Bailey Bozka Joseph Brady Bruce Brannan Brett Brasher Bethany Braune Ashley Bravo Matthew Bray Steve Bray Jeremy Bridges Randall Bridges Emily Brink Jolene Brittain Carlene Britton-Carrington Amanda Brock Joshua Broemer Jason Brogdon Ben Brooks Bill Brooks Michael Brooks Myron Brooks Jack Brophy Kevin Brophy Brandon Brown Carola Brown Chris Brown Chris Brown Derek Brown Dillon Brown Glen Brown Jeff Brown Kenneth Brown Marty Brown Natalie Brown Randal Brown Steven Brown Tammie Brown Bruce Brumley Lance Brumley Josie Brunick Christopher Bruno Linda Bruster Young Clay Bryan Dwayne Bryan Casey Bryant James Buchholtz Greg Buckner Mikhail Budhu Roman Budinskiy Dane Buendel Jaime Bueno Ozzie Bueno Roger Bueno Steve Bugni Phong Bui Denise Bullard John Bullard Kory Bundick Matthew Buoniconti Fayetta Burch Darryl Burger Bryan Burinda Rick Burke James Burkett Eric Burkholder Jennifer Burris Shaun Burris Bennett Burt Laurie Burt Rick Burton Sandra Burton Victoria Bush Rose Mary Bussell Oscar Bustos Lance Butler Lauryn Butler Salman Butt Wade Buxcel Janice Byam Russell Byers Mikel Byers-Scarbrough Dustin Bynum Christina Byrom Flavio Cabello Patricia Cabral Noe Cadena Sheila Cahalane Min Cai Xia Cai Steven Cain Jared Calder Chris Caldwell Abby Calles Robby Callicotte Howdy Cameron Dennis Camino Billy Campbell Cathy Campbell Chad Campbell Dave Campbell Nick Canava Steve Canion Mike Cannon Concha Cano Kenny Cantrell Robert Cantu Jr. Nina Cao Nick Caporale Pedro Capuchin Jose Carbajal John Cardin Mike Carey Steven Carle Patti Carlile Skip Carnes Ronnie Carney Christopher Carpenter James Carpenter Luke Carpenter Hiram Carpio Cary Carrabine Alfonso Carrasco Allison Carrasco Darin Carrasco Fernando Carrasco Bob Carroll Phil Carroll Christopher Carter Misty Carter David Carver Garrett Carver Jake Carver Brandi Casanova Simon Casas Tony Cash Rachel Casillas Dereck Casimir Christopher Caskey Carolyn Cassidy Cathy Castaneda Nick Castaneda Veronica Castilleja Angelita Castillo Charles Castillo Elizabeth Castillo Josh Castillo Rebecca Castro-Lowe Darrell Catchings Jason Cates Jesse Cates Ann Catron Kent Caudle Joseph Cavazos Jonathan Cave Mike Cawley Teresa Cazares Monita Cebell Daniel Cervantes Keith Cervantes Mike Cervantes Sonny Cervantes Ian Cervi Ethan Chabora Sergio Chacon David Chadwick Brenda Chambless Benjamin Chandler Brian Chandler Sophia Chang Korrey Charboneau Albert Charles Kathy-Ann Charles Narvin Charles Jeannette Charles-Martinez Anish Chaudhary Raven Chavarria

Monica Chaves Debbie Chavez Joe Chavez Sheila Chavez Amy Cheatham Cade Cheatham Emily Chen Tom Chen Weber Chen Kristal Cheng Ryan Chennault William Chesnut Dara Chesser Jacob Chew Joseph Chew Deborah Childress Shawn Childs Janice Chin-Wing Drayton Tracey Chong-Ashing Bev Christensen Kyle Christiansen Marcus Christofferson Marcus Chroback Jonathan Chung Kamal Chunilal Sally Cisarik Casey Citty Jeramy Clanton Bert Clark Gregory Clark John Clark Keith Clark Timothy Clarke Chatham Clary Michelle Clary Stephen Claycamp Caleb Claycomb Davro Clements Baron Clifford Jeannie Cluiss Colton Cobb Crystal Cobb Tish Cobb Susan Cockerham Ben Cockrill Sherron Codogan Donna Coe Grace Coffman Frelynn Cohrs Blane Colbert Allen Coldewey Jr. Kurt Coldewey Craig Cole Dale Cole Gary Cole Haley Cole Carolyn Coleman Clay Coleman Jeremy Coleman Micah Coleman Chuck Collier Calvin Collins David Collins Vicki Collins Chuck Colson Matt Conklin Erin Connors Stevan Contreras Tanis Contreras David Cook Evan Cook Lisa Cook Megan Cook Reece Cook RL Cook Robert Cook Renee Coon Tyler Coon Kyle Cooper Ruchira Corey Trent Corkran Cody Cormier Cooper Cornelius Brandon Coronado Jacob Corpron Paul Corrales Javier Cortesia Scott Costner Marc Cote Josh Cotter Pam Cotton Damon Cottrell Heather Couchman Yvette Counts Richard Couture Leon Covell III Alan Covington Jordan Cowan Clinton Cox Crystal Cox Greg Cox Justin Cox Mark Cox Shawn Cox Tyler Cox Andrew Coxon Bette Cranford Kim Crapo Cody Cravens Janice Cravens Bobbie Crawford George Crawshaw Misti Creach Teresa Criddle Chris Crocker Sandy Cromer Taylor Cronje Denise Crook Stacie Crosby Judson Crouch Christopher Crow Trever Crow Barry Crowder Herminia Cruz Megan Cruz Wade Cuch Chris Culver Randy Cumberland Dileon Cummings Reed Cupps Casey Curd Terri Currie Edwin Custodio Matt Dabbs AJ Dach Brian Dahl Joshua Dahly Qi Dai Vivian Dai Michael Daigle Todd Dalessandro Reed Dalton Todd Dalton Wendy Dalton Joey Damiano Barry Dampman Jeremy Daniel Marsha Danzell Jeremiah Darr Whitney Darr Sagar Das Loni Daub Magaly Davila Dave Davis Dustin Davis Gina Davis Ilena Davis Kelsey Davis Kyle Davis Logan Davis Matt Davis Matthew Davis Michael Davis Samantha Davis Stephen Davis Tim Davis Trevor Davis Andrew Dawson Kevin Dawson Christopher Day Matt Day Portia De Four Allan De Leon Erica De Leon Nick De Leon Tricia De Souza Cameron Dean Lisa Dean Andrew Deane Cambron Deatherage Sherri DeBakey Joe Decker Fred Dehoyos Juan Del Rio Terry Del Rio Jennifer Del Tatto Daisy Del Val Esteban Del Valle Olga DeLand Steve DeLand James DelCampo Joseph DelCampo Juan DeLeon Brenda Dellinger Derek DelPriore Tyler Denham Jim Denman DaLina Dennis Ikky Deol Davis DeSautel Olivia Desser Kyle DeTienne Patrick Dew Nivid Dholakia Otto Dick Debbie Dickey Andrew Dickins Stuart Dickson Andrew Dietz Casey Dietz Jeff Diffely JP Dillard Nikki Dillard Eric Dille Trudy Dillon Liesel Dionisio Nathan Dirks Mark Dixon Trevor Dobbs Annette Dobson Jonathan Dodd Corbin Doffer Tatum Dolan Georgeanne Dollar Manuel Dominguez Pete Dominguez Kathy Donaldson Michael Donaldson Stacey Donaldson Matt Dotin Anita Douglas Brendan Douglas Eric Douglas Frank Dowell Larraine Drake Joel Draper Tim Driggers Clint Driskill Dannon Drosdal Claudia Duenas Kevin Duff Zac Duff John Dugas Cindy Duge Trixy Duke Shannon Dumolt Daniel Dunaway James Dunn Ashley Dupont George Dupre Bernabel Duran Doug Durand Pankaj Dureja Adrian Durham Hannah Durkee Tell Dyer Eric Dyke Robert Eales Joe Earley Dane Eccles Daryl Eccles Kelsey Echols Stacey Eddings McKenzie Edmondson Josh Edwards Michael Edwards Pat Edwards Danielle Edwards-Dupay Kurt Eggebrecht Clint Egger Erick Ehler Kimberly Ehmer Judy Elizalde Keith Elliott Ashley Ellis Kathy Ellis Ryan Ellis Scott Ellis Casey Ellison Dirk Ellyson Thomas Elmer Jeffrey Elsworth Courtney Emerson Shawn Engberg Joey Engelhart Chris Enger Brandon Englert Jennifer Engles Marissa English Kelsey Enke Silvia Enriquez Colton Epps Marsha Erskine Carl Ervin Duane Ervin Nicholas Esker Doug Esmond Jaime Espinosa Cynthia Espinoza Victor Esquibel Marcus Estes Sandra Estrada Alvaro Estrello Joe Estvold Mark Evanoka Debbie Evans Joe Evans Skyler Evans Steven Evans Russell Evatt Riker Everett Garrett Ewald Christine Fallon Danielle Fanovich Matthew Fare Logan Farmar Naomi Farmer Karin Farquhar Ryan Farquhar Mike Farris Samad Fassihi Eileen Faulk Gabrielle Faustin Bradley Fehner Andrea Felix Nick Felix Shelley Fellenstein Chelse Felts Nina Feng Samantha Fernandez Ashlee Ferrel Brian Fiegl Janah Fielding Shawn Filcaske Scott Filz Clayton Fisher Judy Fisher Ryan Fiske Haleigh Fitzgerald Van Flaherty Craig Flatt Michael Flax Julie Fleetwood Jason Fleniken Amber Fletcher Marty Fletcher Sherry Fletcher Mitchel Flick Adrian Flores Marco Flores Nicolas Flores Nicole Flores Sara Flores Sonia Florez Tristen Folden David Follingstad Emily Follis Blake Fontenot Kirk Foreman Kenny Forrester Adam Fossett Brice Foster Kenneth Fougerat Andrew Foulkes Patricia Foulkes Meredith Fowler Nancy Franco Chris Frank Chad Frederick Danny Frederick Jason Frederick Rickey Frederick Jamey Fredrickson David Freeland Brian Freeman Jacob Freeman John Freeman Yasmin Freeman Kevin Fretheim Sara Frost Patrick Fry Joel Fuentes Laura Fuentes Matt Fuller Jonathan Funk Monica Gabaldon Claire Gable Jared Gabro Sarah Gach Mason Gadberry Johnny Gaines Iliana Galan Ricky Galan Weston Gallo Ademar Galvan Roy Galvan Vicente Galvan Gregory Gammage Chelsea Gamron Ryan Ganaway Shabbir Gandhi Aaron Gandrud Jamie Gandrud Shuresh Gangabissoon Kapil Gangapersad Nathan Gann Cora Gant Terry Gant Mariela Gaona Perez Paul Garafalo Peter Garbee Cesar Garcia Joe Garcia Nancy Garcia Tony Garcia Reggie Garcille Cody Gardiner David Gardner Joseph Garner Nicole Garner Dwayne Garnett Riley Garrison Tom Garrison Angela Garza Herman Garza Joseph Garza Patsy Garza Adrienne Gasiorowski Katelyn Gast Matt Gastgeb Kyle Gastring Aimee Gates Patrick Geesaman Aaron Geesey Lori Geiger Greg Geis Jared Geis Quaid George Terra George Nic Gergen Derrick Gibson Elaine Gibson Mark Gibson Doug Gilbertson Mason Gill David Gillespie Randy Gillo Christine Gilmore Evan Gilmore John Gilmore Yvonne Gilmore JP Gips Amy Gipson Jim Giuliani Kyle Glein Elmo Glover Rowdy Glover Sravanthi Godugu Garrett Goebel Anelia Gogova Jeff Goldberg Curtis Golde Esmeralda Golden Adam Goldsmith Gregg Gomez Juan Gomez Noel Gomez Travis Gomez Derek Gonet Johnny Gonzales Joshua Gonzales Sam Gonzales Santos Gonzales Abraham Gonzalez Evan Gonzalez Jinnifer Gonzalez Jose Gonzalez Juanita Gonzalez Rick Gonzalez Clint Goodman Gordon Goodman Nicole Goodwin Surendar Gopinath Joe Gordon Steve Gordon Lisa Gosine-Alleyne Steven Gottwald Robert Gough Hillari Gould Aaron Gourneau Terry Gowers Amy Graham Andrew Graham Bridgette Graham Daniel Graham Gene Grant Gordon Grant Michael Grant Morgan Grant Nicole Grant Stephen Grant Dewayne Gray Donald Gray Dortha Gray Jim Gray Joshua Gray Katherine Gray Marc Gray Matthew Gray Mitch Gray Pam Gray Blake Green Bryan Green Jacob Green James Gregory Lauren Gregurek Sandy Grier Alden Griffi n Amber Griffi n James Griffi n Mark Griggs Dallen Grimes Stan Grimes Chelsea Grimm Isaac Griner Wayne Groo Blake Grooms Matt Groves Nick Groves Alexis Guba Christopher Guenthner Jason Guerra Andrea Guerrero Camie Guerrero Carlos Guerrero Joey Guerrero Evelyn Guess Roshend Guevara Christor Guidry Paul Guillory Thera Guin Carson Guinn Darrell Guinn Tyler Guinn Shelly Gummelt Kevin Gunder Hitender Gupta Britnye Gurule Chris Gurule Daniel Gustafson Gerard Gustilo Shaun Guthrie Grace Haas Jeremy Haass Kristin Hagebak Justin Hagedorn Clay Haggard Ashley Hahn John Hahn David Halbrook Alex Hale Casey Hale Christopher Hale Alexander Hall Durk Hall Ethan Hall Josh Hall PJ Hall Max Halmamedov Rodney Halvorson Matt Hamilton Todd Hamilton Wayne Hamilton Le Hammer Brian Hampton Debbie Hamre Jamie Hanafy Kirk Hanberg Loren Hancock Jennifer Hanna Cynthia Hanselman Susan Hanselman DJ Hansmann Kevin Hanzel Ryan Harbor Ricky Hardaway Christopher Harder Badia Hardin Lindsay Harding Nancy Harding Bart Hardman Lindsey Hardouin David Hargrave Sean Harlan Brian Harmann Sharon Harmon Sam Harms Allen Harp Star Harrell Thomas Harrington Daniel Harris Deana Harris James Harris JP Harris Kristy Harris Lucie Harris Pamela Harrison Spencer Harrison Clint Harry Ariel Hart Kayla Harten Lauren Harwell Lee Hastings Shaun Hatcher Mark Hately Tammy Hatfi eld Dale Hathaway Meredith Hatz Michele Hatz Gina Hauck Heather Haught Charlene Havelka Allie Hawkins Tyler Hawkins Joeann Hayes Marshall Hayes Jerry Haynes Haiden Hayward Britt Hazelbush Yong He Yue He Scott Head Brandon Headrick Thomas Hearon Nathan Hedge Shane Heidel Mitchell Heimer Jonathan Helm Blake Helmke Billy Helms Cory Helms Nelis Heltzel James Henderson Kendra Henderson Wacey Henderson Cody Hendricks Myrvrene Hendrickson Rose Henley Dustin Henline Jim Henning Joshua Henning Andrew Hensley Christopher Heny Cory Hepburn Dominique Hepburn Wade Hermanson Eric Hernandez Eryn Hernandez Fernando Hernandez Floyd Hernandez Jorge Hernandez Price Hernandez Raul Hernandez Rene Hernandez Rosie Hernandez Jeremy Herndon Lupe Herrera Steven Herrera Michael Herrington Greg Hersperger Jenna Hessert Brad Hester Collin Heusinkveld Luigi Heydt Mike Heymann Brandon Hickman Jimmy Hickman Michael Hickman Daniel Hicks Jade Hicks Justin Hicks Mickey Hicks Trey Hicks Vicki Hietpas Casey Hilbig Acie Hill Brandon Hill Brian Hill Clay Hill Darius Hill Garrett Hill Harleigh Hill Henry Hill Jesse Hill Karen Hill Lauren Hill Mike Hill Ronald Hill Steve Himes Matt Hinkle Rob Hinnant Rachael Hirsch Luke Hise Eric Ho Steven Hoaglund Linda Hoang Jayna Hobby Clare Hobday Ben Hocher Chad Hodge Jeff Hodge Cecil Hodges Kenneth Hodges Randy Hodgins Tanner Hoelscher Robyn Hofer Darby Hoffman Dusty Hoffman Jessica Hoffman Jim Hoffman Ryan Hoffman Brenna Hogarth Derek Holeman Bryan Holgate Danny Holgate Jared Holgate Daniel Holguin Kasey Holland Nathan Hollek Joel Holleman Sheri Holloway Braden Holmes Brant Holmes David Holmes Derrik Holmes Shay Holte Erich Holzer Heather Hong Dane Hooker Blake Hopkins Ashraful Hoque Salema Hoque Garland Horak Mike Horgan Kane Horner Brett Horton Kate Horton Rishard Hosein Helen Hosein-Mulloon Joanna Hoss Margrethe Hotter Bob Hovanec Dexter Hoverson Rick Hovland Gloria Howard Kit Howard Phillip Howard Jeffrey Howe Linda Howerton Aisha Hozri Jack Huang Sean Huang Courtney Hubbard Bob Hubbert Zachary Hudnall Ann Hudson Brandy Hudson Morgan Huegele Jr. Tina Huerta Angel Huezo Cas Hughes Robert Humphreys Wan-Hsiang Hung Jenna Hunt Kermal Hunt Patty Hunt Keron Hunte Kellen Hunter Laura Hunter Cindy Hur Vue Owen Hurd Judith Hurt Nathaniel Hurt Peter Hurt Michael Hutchings Silvia Iglesias Jack Imboden Laurie Infante Ryan Ingle Scott Ingle Mikayla Inlow Darrell Irwin Mike Isaacs Allan Itz Kelley Ivanova Jacob Ivie Buster Ivory Yvonne Iwo-Brown Bubba Jackson Jeffery Jackson L.J. Jackson Melinda Jackson Shelby Jackson James Jacob Natalie Jacobs Jeff Jacobson Chris James Susan James Katie Jamison Brian Jansen Ann Janssen Darryl Janssen Lluvia Jaquez Tracey Jarmin Alicia Jarvis Wayne Jefferson Emily Jenkins Mandy Jenkins Camille Jenman Tammi Jensch Ryan Jensen Michael Jillson Terri Jimenez Yvonne Jimenez Ling Jin Traci Jiral Brian Johns Jaqueta Johnson Veltz Carolyn Johnson Chad Johnson Corby Johnson Daniel Johnson Denis Johnson Derek Johnson Don Johnson Ian Johnson Jason Johnson Jessica Johnson John Johnson Johnathan Johnson Kayla Johnson Keith Johnson Levy Johnson Matt Johnson Nicholas Johnson Patty Johnson Robert Johnson Shelley Johnson Steve Johnson David Johnston Alex Jones Daniel Jones Edward Jones Emile Jones Jared Jones Jeremiah Jones Joy Jones Kayla Jones Lydia Jones Ray Jones Richard Jones Sherry Jones Zack Jones Casey Jones-Peterson Brandon Jordan Michael Jordan Paige Jordan Tracy Jordan Davey Juarez Joe Justus Michael Kalamaha Ross Kalous Ron Kane Shayena Kanju Jeffrey Kao Teresa Kaplan Chetan Karanth Shane Karhoff Janene Kauffman Mark Kay Jill Kean Allison Keator Jim Keenan Branden Keener James Keeton Lex Keim Chad Keller Edgar Keller Seth Kelley Brendan Kelly Steven Kelly Ted Kelly Brandon Kennedy Bryce Kennedy Chris Kennedy James Kennedy Michael Kennedy Steve Kennedy

77284.indd 2 3/10/21 2:25 PM Tammy Kennedy Ronald Kenny Jennie Kent Kyle Keplin Garrett Kerbs Sean Kessel Paul Kessler Kim Keyser Alicia Khadaroo Usman Khan Pratik Kharel Mimi Khatiyavong Alex Khorram Bob Kidney Casey Kidney Colin Kiernan Kristen Kifer Jacob Kikone Michael Kilen Spencer Kimball Billy Kimbro Steven Kincaid Ashley Kinder Dustin Kinder Brian King Efrem King Mark King Richard King William King Jodi Kipp Jeff Kippen Nan Kippen Andrew Kircher Judy Kirian Alex Kirkendall Amanda Kirkham Carol Kirksey Colt Kissling Leesel Kissoon James Kittley Tony Klarmann Jim Klein Susan Klein Darren Kleinschmidt Julie Klepac Adam Kline Jennifer Knickerbocker David Knier Ron Knippa Todd Knuth Randy Koehler Kelly Koehn Everett Koelling Amanda Koenning Anthony Koester Greg Kohlhof David Kondret Eric Koppinger Joe Korenek David Kos Bob Kosa Sri Kotela Alan Kothmann Daniel Koury Lucy Kowis Ashton Kozeal Joseph Kozeal Michael Kozowyk Karey Kramer Joshua Kravitz James Kress Miles Krieger Tyler Krug Kevin Kuitu Tan Kulachanpises Abhinav Kumar Sapna Kumar Eric Kuntschik Sarah Kuo Jim Kurowski Eleonora Kuruc Jim Kuster Kenny Kuykendall Kevin Lacey Shane Ladewig Vick Lagad Craig Lahodny Agnes Lai Andrew Lai Chaz Laijas Philip Lamsens Jackson Lancaster Luzbella Lancaster Christian Lancheros Jeff Landrum Randy Landrum Thomas Landrum Joe Landry Clinton Lane Jared Lane Brooke Langford Sean Langhout Bryan Lanier Chris Lanning Dean Lantrip Ny Lantrip Reese Lantrip Michael Lapp Dusty Laqua Mickenzie Larsen Roy Larson Brock Laskowski Ahmad Latifzai Denver Lauger Louie Lavallie Taylor Lawrence Cynthia Lawson Donnie Lawson Dusty Lawson Thang Le Jaime Leal Madison Leaverton Brandy Ledbetter Letitia Ledesma Wesley Ledoux Brittany Lee Kevin Lee Megan Lee Michelle Lee Dwayne Leera Philip Leimer Chance Leininger Jeffrey Leitzell Jason Lemar Logan Lemieux Heath Lemon Jacquelyn Leonard Dan Letch Brice Letcher Dillon Letherman Herman Leung Roberta Levick Tom Levitz Angie Lewis Kande Lewis Katie Lewis Neil Lewis Adam Ley Chris Leyendecker Helen Li Robert Li Mike Liang Allen Light Jackie Lightner Audrey Lilley Shannon Lillie Steven Limon Jie Lin Margaret Lin Samantha Linde Douglas Lindsay Bradley Lindsey Michael Lindsley Eric Lippincott Kelsey Liska Benjamin List Scott Listiak David Little Henry Liu Ji Liu Newton Liu Martin Livingston Erin Lloyd John Lock Brian Locke Andrew Lockhart Amber Long Dave Long Jeffery Long Jennifer Long Chris Longoria Rey Longoria Brandyn Lonning Brian Lopez David Lopez Denise Lopez Donna Lopez Jerome Lopez Juan Lopez Mateo Lopez Michael Lopez Michelle Lopez Robin Lopez Jeffrey Lorson Dustin Lott Cary Loughman Brent Louser Shaun Love Doug Lowrie Javier Lozano Jeremy Lozolla Andrew Lu Josh Lucas Eric Luckey Nina Luckey Ector Lujan Jr. Steven Lukas Alexey Lukyanov Anibal Luna Chelsey Luna Davis Lunsford Paul Lunsford Elizabeth Luu David Ly Eric Lyche Jocelyn Lyrock David Lyssy Nick Lyssy Tyler Macfarlane Daniela Machnik Alfredo Macias Arthur Mackey Paula Mackey Nicole Macmillan Rachel MacWithey Kyler Macy Stuti Madaan Blake Maddoux Kay Maddox Zach Madrazo Brandon Madrid Malissa Magee Devanand Maharaj Adam Majeski Sarah Majors Geri Malcolm Christina Maldonado Dewayne Malina Nick Malinaric Arvind Mallya Shawn Malsam Grace Mamaradlo Lauren Manning Don Manton Katie Manton Wesley Maples Ken Marbach Anita Marin Pablo Marin Anthony Marino Victoria Mariscal Colleen Marples Alex Marquez Michael Marquez Miguel Marquez Patrick Marsh Michelle Marshall Savannah Martell-Durkin Amanda Martin Hallie Martin Matthew Martin Reese Martin Rodney Martin Susan Martin Claudia Martinez Corrina Martinez Fernando Martinez Jeanette Martinez Jimmy Martinez Mark Martinez Paul Martinez Rick Martinez Roland Martinez Santiago Martinez Tabitha Martinez Tori Martinez Zachery Martinez Margaret Martinez-Soza Leonardo Maschio Aaron Mason Ashley Mason Matt Mason Lynn Mast Domingo Mata Rachel Matas Chris Mathews Beverly Matthews Mac Matthews Tyler Matthews Kaylee Mattox Joseph Matula Alec Mauritsen Colter May Emilee May Paige May Christopher Mayers Anthony Mayes Ashley Mayfield Donnie Mayo Gene Maze Tyler McBeth Katie McBryde Charles McCann David McCann Rex Mccarley Melissa McCarty Rick McCaslin Sophia McCatharn Adam McCauley Kacey McCauley Rowdy Mccauley Amy McCauslin Mitchell McCauslin Colby McCay Tabitha McChesney Vanesa McClain Tanda McConnel Thomas McCormick Stan McCracken Susan McCraney Denise McCray Johnny McCray Jason Mcculloch Robert Mcculloch Tyler McCulloch Michael McDaniel Drew McDiarmid Shay McDonald David McDougall Andrea McGarrah Bonnie McGehee Ronald McGinnis Vickie Mcginnity William McGough Matt McGuire Kimery McKaskle Rowdy Mckendrick Jacob McKenzie Michael McKenzie Cloman McKinney Mark Mckinney Scott McKinney Ross McLaughlin James McMath Raina McMillon Courtney McNeese Curtis McTeigue Rick Mead Aubrey Meadors Andrew Mealey Oscar Medellin Anacani Medina Thomas Medrano Andrew Mehlhop Owen Meinke Gabriel Mejia Carlos Melick Stephen Melnyk Ellen Melstrom Brad Melton David Men Ethan Mendel Jackie Mendoza Patrick Mendoza Iranell Menefee London Mery Patrick Messina Mark Metzger Jeff Meyer Lauren Meyer Rob Meyer Zachary Meyer Eloise Meza Jane Mi Bryan Michalak Michael Michalak Ryan Michel Sunil Mickelson Travis Mihecoby Traci Mikes Jeremiah Miles Matt Miles Scott Miles Shante Miles Joe Milke Alex Miller Brittany Miller Charles Miller Christopher Miller Edward Miller Greg Miller Rick Miller Sara Miller Tigar Miller Joseph Millican Jinay Mills Leroy Mills Billy Milner Andrew Mioduchowski Arnaldo Miranda Daisy Miranda Amy Mitchell Robert Mitchell Austin Mobley Justin Mocko Dana Moczygemba Jennifer Modrick Chance Mogg Saaliha Mohammed Shazam Mohammed Ganesh Mohanrao Ahad Momin Chelsea Monahan Tony Monariti Christopher Monger Jordan Monger Byron Monk George Monk Joel Monroe Rachael Monroe Randy Montalvo Jeremy Montanez Trini Montes Gerardo Montoya Miguel Montoya Max Monty Ryan Moody Laura Moon Dave Moore Yvette Moore Daniel Moose Cindy Mora Eunice Morales Montelongo Abran Morales Andrea Morales Miriam Morales Anna Morgan Lisa Morgan Michael Morgan Nancy Morgan Ted Morgan Gordon Morrin Andre Morris Colby Morris Jared Morris Ashley Morrison Heath Morrison Jake Morrison Wes Morrison Matthew Morse Bob Mosemann Anne Moses Kyle Mosley Michelle Motsch Nephi Mourik Clayton Moy Pat Moya T.J. Moye Greg Mudgett Sonal Mujmer Jeremiah Mullen Jim Mullen John Mullican Karen Mullins Norma Muncy Omar Muniz Joel Munoz Jose Munoz-Carrillo Steve Munsell Madhavi Muralidhar Daniel Muren Joseph Muren Duberney Murillo Manny Murillo Bill Murphy Courtney Murphy Emily Murphy Grady Murphy Katie Murphy Sam Murphy Katherine Murrell Bryson Murry Ramey Musgrave Kendra Myer LB Myers Harry Nanan Melissa Nance James Nanney Laura Napier Camille Nath Rachel Natividad Sylvia Navarrette Debra Navratil Lev Nayvelt Brian Neemar Raymond Neether Amanda Nelson Gary Nelson Clint Neshem Doug Ness Jason Neugebauer Jenny Newkham Terry Newland William Newland Dean Newman Bonny Nguyen Hanh Nguyen Hung Nguyen Tu Nguyen Tuyen Nguyen Yen Nguyen Joseph Nicholas Kory Nickell Jonathan Nider Cory Nielsen Mary Nienkamp Richard Nies Orrison Niles Sherly Nissing Cat Nix Scott Nordstrom Charles Normann-Petersen Joel Noronha Brian Norris Tracey Norris Charles Northern Vanessa Nunez Pancho Nye Amy O'Boyle Ben Ochoa Ryan O'Connell Shane Odell Ron Oden Laura Odom Lori Odom John O'Donnell Amos Oelking III Chieke Offurum Geoffrey Ogden Rick Ogle Jamie Ogletree Julie Ogren Mark O'Koren Danny Olds Shawn Oleson Sergio Olivas Victoria Olivas Raul Oliveira Dillon Oliver Jay Oliver Mathew Oliver Tisha Olkowski Kevin Olsen Dan Olson Christine Omadath Carrissa O'Meara John Omovie Cody O'Neal Denton O'Neal Julia O'Neal Tracy Opp Audrey Orenday Kaitlin Oress Jeremy Ormsby Guillermo Orquiz Rosa Ortega Ama Ortez Diane Ortiz Gaby Ortiz Peter Ortiz Cary Osiek Nikolus Osiek Kelly Ostdahl PJ Ostlund Craig Ostriyznick Casey Ott Jennifer Otterson Angelica Oubre Todd Overson Dayna Owens Jessica Owens Tatiana Pablo Manuel Pabualan Bryce Pace DeWayne Pace Sergio Pacheco Sylvana Pacheco Jerome Packineau Chad Paden Patrick Padilla Vamsi Pallem Jennifer Palma Joe Palma Debra Palmer Amy Palmieri Dom Palmieri Penny Pan Neel Panchal Michael Pando Liz Panfely Troy Pank Matt Paquette Manuel Pargas Jazmin Parham Allison Parizek John Park Cullen Parker Hillary Parker Kevin Parker Ancil Parks Ashley Parr Ryan Parsons Shane Pate Rati Patel Colin Patrick Tara Patten Brent Patterson Jay Patterson Rob Patterson Brenna Patton Dallas Patton Doug Patton Anton Paul Jesse Pauls Bill Pauly Jason Pawelek Landon Pawlik Justin Payne Oscar Payne Rafael Paz Rhonda Pearce Wes Pearigen Annette Pearsall Michael Pearsall Philip Pearson Ty Pearson Sarah Peasley David Pederson Bret Pehacek Ignacio Pelayo Jody Pelzel Jessica Pena Gina Pendleton Gary Peng Samuel Pennington Ginny Penzell Sterling Pereira Erick Perez Martha Perez Ruben Perez Shonna Perkins Christian Perner Narine Persad Neil Persad Roy Persohn Debbie Personette Bradley Peters Brett Peters Sean Peters Brian Peterson David Peterson Kyle Peterson Frank Petrutsas Luke Pettinga Angela Pettus Anh Pham Phuong Pham Rita Pham Tai Pham Ted Pham Tony Pham Tri Phan Curtis Philip Gary Phillips Nestor Phillips Saunda Phillips Laura Piasecki Michael Pickell Sammy Pickering Jake Pickett Elisabeth Pieper Dave Pieprzica Kyle Pierskalla Sonja Pigeon Clint Pigg Scott Pilling Silvestre Pineda Christopher Pinson Catalin Pintea Keith Pipkin Joshua Pitman Catherine Plasencia Robert Pledger Stephanie Poe Jami Pohl Justin Polasek David Pollok DeAnn Pollok Brian Pond Garret Pooley Batina Poorbaugh Preston Pope Brianna Popowicz Lily Portales Brandon Porter Brian Porter Chris Porter Jeremy Porter Will Porter Jeff Porzondek Diane Posey Craig Poskus Barrett Poth Phani Potturu Michael Pouba Navan Powers Brandon Prasek Brian Prasek Cary Pratka Jon Pratt Judy Prentice Christy Prescott Eli Presson Jon Prestwood Debbie Price James Price Diana Pridgen Christina Prigmore Troy Pritchard Brittany Pritchett Melissa Procopio Stephen Proksell Aaron Pullin Dusty Pullin Conrad Puls Jennifer Puzon Jeremy Pyle David Pyles Benny Quezada Shawn Quimby Judy Quintana Oelke Rick Quintela Irtiza Qureshi Michael Raab Shawn Racca Erick Rada Reese Rademacher Amanda Radford Richard Raghoonanan Casey Ragsdale Taryn Ragsdale Quazi Rahman Shashank Raizada Kishan Ramdeo Rennie Ramdeo Jay Ramineni Andrew Ramirez Diana Ramirez Eric Ramirez Luz Ramirez Priscella Ramirez Renelle Ramirez Rudy Ramirez Nigel Ramkhelawan Ann Ramlochan Bonnie Ramon Perla Ramos Ricky Ramos Anuradha Ramprakash Damian Ramsey Navindra Ramsingh Vishal Ramsook Hector Rangel Gary Ranger Tammy Rankin Jamie Raphael Dustin Rasmussen Julie Rasmussen Larry Rasmussen Rance Rasmussen Justin Rasmusson Surath Rath Cass Rathmann Jason Rauen Stuart Ray Gilbert Rea Michael Read Lauren Redmond Bo Reed Bradley Reed Joni Reeder Cody Reeh Trent Reese Becky Reeves Garrett Reeves Derek Reiber Tracy Reid Trent Reiner Jeremy Reinhard Matt Reis Christopher Rendall Cody Renken Wade Renken Miguel Retana Renee Retana Travis Rettig Lee Reuter Julie Rey Daniel Reyes Danny Reyes Patty Reyes Roland Reyes Ruth Reyes Ricardo Reyna Brian Reynolds Russell Reynolds Ryan Reynolds Jeff Rezac Cristin Rhinehart Aaron Rhoades Chad Rice Michael Rice Cory Richard John RiChard Austin Richards LeeRoy Richards Janet Richardson Robert Richardson Mark Richeson Alex Richter Kate Richter Lynn Richter Shane Rickerson Grayson Ridgway Janice Riedel Donna Riggs Kendra Riggs Israel Rios Robert Rios Kim Risner Shane Rithmiller Kimberli Rivas CeCe Rivera Jesus Rivera Roy Roach John Robalin Glen Robbins Johnnie Roberts Rachel Robertson Lisa Robichaux-Jones Jordan Robinson Kyle Robinson Rob Robinson Sam Robinson Jeremy Rochell Elitha Rocke-Maharaj Chance Rodgers Colter Rodgers John Rodgers John Rodney Alex Rodriguez Casey Rodriguez Daniel Rodriguez David Rodriguez Denzeal Rodriguez Esther Rodriguez Jason Rodriguez Jason Rodriguez Maryann Rodriguez Mayra Rodriguez Michelle Rodriguez Nate Rodriguez Pilar Rodriguez Victor Rodriguez Dana Roesler Ben Rogers Brandon Rogers Jerod Rogers Phillip Rogers Celeste Rohde Wendy Roman Larry Romero Alex Romo Carlos Romo Juan Romo Miguel Romo Robin Rood Seth Rorem Larry Rosales Juan Rosas Jessica Rosasco Jeff Rosato Bradley Rose Greg Rose Randy Rose Pamela Roth Dallas Roundy Reed Roush Don Rowell Kyle Royal Dan Rozman Puri Rudick Robert Ruff Fabiola Ruiz Pelayo Alexander Ruiz Jose Ruiz Sarah Ruiz Doug Runkel Michelle Russell Will Russell Trint Rust Bradley Ruth Amy Rutledge Travis Rutledge Mel Ryan Matthew Sabolchick Teresa Sadlowski Ashley Saelens Carlos Saenz Nevarez Sandy Salazar Eduardo Saldana David Saldarriaga David Saldivar Gloria Salinas Samantha Salinas Taylor Salness Jimmy Sanchez Willie Sanchez Bobby Sanders John Sanders Randall Sandiford Kathy Sandoval Skylar Sandoval Ancil Sandy Ben Sangchat Ram Sankar Michael Santistevan Jonathon Santone Juan Sarabia Okan Saran Daniel Sargent Raul Sarmiento Nick Sauby Rodney Saucedo Rolando Saucedo Chris Saunders Chloe Sawtelle Katy Scates Jeremy Schaffer Amber Schaller Garrett Schank Kelly Scharkopf Jacob Scheel Brett Scheeler Wendi Scheier Stephen Schelling Carrie Schelnick Billy Schindler Colby Schindler Katy Schindler Steve Schindler Brooke Schlemeyer Frank Schmidt Jake Schmidt Jon Schmidt Nathan Schneider Nicholas Schneider Jr Schock Ty Schoon Carol Schornack Mark Schram Jan Schroller Eric Schulz Steven Schulz Paul Schwarz Andy Scott Pat Scott Zachary Scott Dave Scourfield Brian Scroggins Phillip Scruggs John Scull Sarah Searle Urban Seay Tom Sebastian Derek Secrest Leandre-Marie Seedansingh Stuart Seger Oscar Segovia Abel Segura Baljit Sehbi Brandon Seidel Brad Sekula Michelle Selensky Stephen Self Sarah Semer Carlos Seminario Meghan Sennett Christine Senter Peter Sepulveda Brian Serrata Bodee Sessions Chase Settle Chris Settle Diana Sewdass-Dabiedeen Chance Sexton Austin Sharp Warren Sharp Dustin Sharpe Reid Sharpe Blake Shaw Gary Shaw David Shedlowski Chuck Shelton Jeremy Shelton John Shelton Charlie Sheppard Ying Shi Mike Shin Lee Shipman Matthew Shoemaker Kevin Shomette Andrew Shorrosh Keith Shuffler Peter Si Jon Sicola Aamir Siddiqui Usman Siddiqui JD Siddoway Jay Siebens Kiel Sieckmann Antonio Sierra Akash Simlote Drew Simmons Steven Simmons John Simon Chuck Simons Justin Simpson Matthew Simpson Palmer Simpson Jerilynn Sims Shivanand Singh Sanchit Singhal Tim Singley Suvinay Sinha Mike Sipps Dennis Sissell Jason Sitchler Everett Skelton Joel Slaskey Hannah Slimp Matthew Slocum Brannon Slusher Summer Smart Jeff Smetanka Aubrey Smith Bobby Smith Caleb Smith Debbie Smith Drew Smith Jamie Smith Jereme Smith Kimberly Smith Larry Smith Leslie Smith Lori Smith Mark Smith Marty Smith Mason Smith Matt Smith Michael Smith Rachael Smith Richard Smith Shawn Smith Taylor Smith Teresa Smith Todd Smith Kyle Smuin Bobby Snow Tyrel Snow Michael Sohmer Annette Sole Olivia Soliman Eddie Solis Karina Solis Annie Soliz Garron Solomon Martha Solomon Noah Son Carlos Sonka Higinio Sonora Nandini Sooklal-Balgobin Joel Sooter Clay Sorrells Michael Sosnowski Cassandra Soto Drew Soto Reid South Wayne South Angel Sowers Alan Spears Anslem Spears Debbie Spears Kelly Spears William Speckels Woody Speer Christine Spencer Deida Spencer Marielle Spinks Lindsay Spooner Ashley Springer Shawn Springfield Laura Sproles Namratha Srikanth Suryaprakash Sripada Vikram Sriram Eric St John Kristina St. Romain Adam Stafford Kristy Stahl Tammy Stambolis Korey Stammen Scott Stammen Anthony Stanton Bridgett Staples Kiera Staples Cindy Stapleton Mike Stapleton Charlie Steel Chad Steele Lisa Steele Morgan Steele Patti Steely Shari Stefinsky Geoffrey Steiner Justin Steir John Stelzer Jake Stephens Sheri Stephens Nathan Stephenson Kim Stetler Christopher Stevens Colleen Stevens Daniel Stevens Jodi Stevens Michael Stevens Brett Steward Brady Stewart Eric Stewart George Stewart Michele Stewart Richard Stewart Suzanne Stewart Zoltan Stiffel Cory Stinnett Jerry Stinson Jeff Stofa Austin Stoller Ted Stoltenberg Natalie Stone Ryan Storro Parker Stovall Cindy Stowell Jeff Strahan Josh Stralow Dan Strawn David Streit Laci Stretcher Brandon Stricker Cody Strickland Tyler Strieber Vicky Strom Rusty Stroschein Dmytro Stryzhyboroda Alex Stuart Jody Stuart Melissa Sturm Jorge Suarez Chris Subia Pete Subia Jason Sugg Barry Sukal Sue Sule Bobby Sullivan Taylor Sullivan Stacy Suphal Brandon Swain Lacie Sweet Sundai Swinney Sharon Sword Stephen Sypult Caightlyn Ta Valarie Taber Jeb Tachick Curtis Tagliabue Ross Talboom Roland Talley Cristina Tamayo Peter Tan Scarlett Tang Brian Tapp Daniel Tate David Tate Abbey Taylor Clif Taylor Clint Taylor Cody Taylor Daphne Taylor David Taylor Dax Taylor Graham Taylor Jackson Taylor Jacob Taylor John Taylor Kelly Taylor Lauren Taylor David Tegtmeier Tyson Teichert Ralph Telford Jason Temple Corey Terrance Jesse Terrazas Josh Terrell Cameron Terveen Lance Terveen Liz Thai Rachana Thakkar Harshitha Thallaparthi Kyle Thebeau Cody Thiel Alex Thomas Bill Thomas Jeremy Thomas Kelsey Thomas Martin Thomas Melva Thomas Stephen Thomas Tammy Thomas Brian Thompson Drew Thompson Jerry Thompson Kelcey Thompson Kendra Thompson Mark Thompson Shea Thompson Steve Thompson Greg Thornton Thomas Thornton Marcel Threat Jack Tidholm Zac Tidholm Dewayne Tidwell Dinah Tiff Marisol Tijerina Justin Tikhonoff Jimmy Timbre Patrick Timlick Tim Timmerman Beau Tinnin Andrell Titte Chistopher Titzman Scotty Tjepkes Madalena Toland Jennifer Tomblin Christel Tomwing Mehmet Torcuk Stephanie Torres George Toscano Charline Townsend Jason Townsend Stephanie Toy Clarence Trader Ryan Trader Dalton Tramell Wayne Trammell Nick Tran Paul Tran Tan Tran Tien Tran Tony Tran Lisa Trascher Keith Trasko Gary Travis Tyler Treece Benjamin Trees Nik Treffert Justin Trestrail Jennifer Trevino Roland Trevino Vale Trevino David Trice Dejan Trifunovski Tyler Trimble Ike Tripp Jonell Trodlier Michael Trout Rachael TRUE Jennifer Trueblood Bobby Trujillo Shane Trulson Brandt Tucker JD Turbiville Larry Turbiville Derrick Turner Kelly Turner Nicole Turner Elodie Tusac Husein Tyebkhan Ben Tyler Casey Tywater George Ulmo Keelan Umbarger Joe Umphres Tull Umphres Amanda Underwood James Underwood Bryan Untereiner Raghu Upadhyay Dustin Upton Bradley Uran Joe Urbis Christina Uribe Tammy Vader James Vaiana Andrew Valdez Eddie Valek Austin Valencia Joshua Valencia Keith Valentine Rey Valenzuela Monica Valeriano-Palacios Kelly Valerio Steve Valero Jaime Valles Chris Valvaneda Cary Van Degna Brent Van Gorkom Tom Van Ierland VK Van Kirk Chase Van Valkingburg Brenda Vaness Rocio Vargas Jonathan Vargo Mike Vargo Martha Varice Kyle Varisco Bridger Vaselin Brandon Vasey Angela Vasquez Antonio Vasquez Cissy Vasquez Erma Vazquez Jennifer Vega Isaiah Vela Cesar Velazquez Dave Vennes Russell Vera Anjali Verma Diva Verma Natalya Verner Christian Vieira George Vieira David Vigil Elling Vikesland Elizabeth Villa Kristian Villa Eric Villanueva Guillermo Villarreal David Villegas Issac Villegas Casey Vincik John Vines Travis Visitew Michael Vito Tim Vogler Prody Vong Jordan Vonroeder Diana Voss Sandy Vu Darren Wacha Haley Wade Pamela Wadham Sandeep Wagle Jessica Wagner Tony Wahus Casey Walk Gary Walker John Walker Kyle Walker Mark Walker Tracy Walker Justin Wallace TJ Waller Josh Wallis Michele Walls Wanda Walls Dylan Walrond Rall Walsh Joseph Walthall Chuck Walton Cindy Wang Xinchuan Wang Ralph Warby Justin Ward Katie Ward Kelsey Ward Lance Ward Melissa Ward Travis Wardlaw Zachary Wardlaw Scott Ware Jackie Warner Ben Warren Daniel Warren Tamara Warton Andrew Washburn Lucas Watkins Danielle Watson Laura Watts Chinmay Watve Kristyn Weaver Mike Weaver Chris Webb Heidi Webb Jake Webb Cody Weddle Damon Weger Grayson Wegner Zoe Wei Derek Weicht KC Weiland Brandt Weimar Erin Weimar Colby Welch Creighton Welch Dustin Welch Geoff Welch Kelly Welk Laura Wellman Amanda Wells Nathan Wells Tina Wells Todd Wells Tonya Wemm Amy Wen Thomas Wenk Steve Wentworth Cally Wescoat Brian West Jeremy West Robert West Brandon Westerholm Erica Westphalen Ty Westphalen Katie Wethington Niles Wethington Julie Whalen Luke Whidden Michelle Whidden Justin Whipple Roland Whitaker Jennifer White Keri White Kris White Matthew White Matthew White Mike White Tatiana White Taylor Whitecotton Mark Whiteley Josh Whitener Kevin Whitley Ron Whitmire Jessica Wiatrek Jonathan Wiatrek Troy Wiatrek Andrew Wiechman Cody Wiens Shane Wiest Richard Wilde Mark Wiley Trace Wilhoit Blake Wilkins Dustin Wilkins Kristy Wilkins Robert Wilkins Sharon Wilkinson Michael Willcox Dale Willenbring Andrew Willett Ron Willett April Willette Aaron Williams AJ Williams Anthony Williams Cody Williams Janet Williams Joey Williams Raegan Williams Rick Williams Robert Williams Greg Williamson Matthew Williamson Brandon Wilson James Wilson Kathie Wilson Roger Wilson Timothy Wilson Nina Wiltz Corey Windham Jeffrey Winkelhake Wink Winkelman Brian Winkleman Dustin Winkler Kris Winland Steven Winn David Winters Jared Wolf Shelia Wolfe Jesse Wolgamott James Wollenburg Mary Womack David Wood Jefferson Wood Justin Wood Lanny Wood Whitney Wood Seth Woodard Andrew Woods Pat Woods Justin Woodward Heath Work Kacy Work Seth Workman Robert Worley Lloyd Woychuk Cameron Wright Dan Wright Marissa Wright Junjie Wu Justin Wyatt Hong Xiao Julian Ximenez Ezra Yacob Anant Yadav Adam Yanes Michael Yang Nikki Yang Raymond Yang Ryan Yarger Malcolm Yates Otis Yates Randy Ybarra Yolanda Ybarra Vijay Yelaka Michael Yemm Barbara Yin Lau Yip Joe Yohe Maggie Yokley Russ Young Sherman Young Jarrod Youngblood Amanda Yourick Cissy Yu Eric Yu Jennifer Yu Melissa Yuan Alisha Zachary Josh Zahn Omar Zakaria Zack Zakaria Sarah Zankey Saeed Zargari Miguel Zavala Tommy Zhang Tracy Zhang Andy Zheng Tracy Zhou Matthew Zidek Zach Zigmond Maison Zuber Amber Zuchara

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EOG-AR-2020-Inside.indd 2 3/5/21 1:54 PM 77284.indd 4 3/10/21 2:25 PM 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, 2020 or ☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 Commission file number: 1-9743

EOG RESOURCES, INC. (Exact name of registrant as specified in its charter)

Delaware 47-0684736 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 1111 Bagby, Sky Lobby 2, , 77002 (Address of principal executive offices) (ZipCode) Registrant's telephone number, including area code: 713-651-7000

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

Title of each class Trading Symbol(s) Name of each exchange on which registered Common Stock, par value $0.01 per share EOG Securities registered pursuant to Section 12(g) of the Act: None.

Indicate by checkmarkifthe registrant is awell-known seasoned issuer, as definedinRule 405 of the Securities Act. Yes ☒ No ☐

Indicate by checkmarkifthe registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes ☐ No ☒

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

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

Indicate by check mark whether the registrant is alarge accelerated filer, an accelerated filer, anon-acceleratedfiler, asmaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act. Large accelerated filer ☒ Accelerated filer ☐ Non-accelerated filer ☐ Smaller reporting company ☐ Emerging growth company ☐

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

Indicate by check mark whether the registrant has filed areport on and attestation to its management's assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒

Indicate by checkmarkwhether the registrant is ashell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒

State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant's most recently completed second fiscal quarter. Common Stock aggregate market value heldbynon-affiliates as of June 30, 2020: $29,444 million.

Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date. Class: Common Stock, par value $0.01 per share, 583,563,479 shares outstanding as of February 12, 2021.

Documents incorporated by reference. Portions of the Definitive Proxy Statement for the registrant's 2021 Annual Meeting of Stockholders, to be filed within 120 days afterDecember 31, 2020,are incorporated by reference into Part III of this report. TABLE OF CONTENTS

Page PARTI ITEM 1. Business 1 General 1 Exploration andProduction 1 Marketing 4 Wellhead Volumes and Prices 5 HumanCapitalManagement 6 Competition 7 Regulation 7 OtherMatters 11 Information About Our ExecutiveOfficers 12 ITEM 1A.Risk Factors 13 ITEM 1B.Unresolved Staff Comments 26 ITEM2.Properties 26 Oil and GasExploration andProduction -Properties andReserves 26 ITEM3.Legal Proceedings 30 ITEM4.Mine Safety Disclosures 30 PART II ITEM5.Market forRegistrant'sCommon Equity, Related StockholderMattersand IssuerPurchases of Equity Securities 30 ITEM6.Selected Financial Data 32 ITEM7.Management'sDiscussion andAnalysisofFinancial Conditionand ResultsofOperations 33 ITEM7A. Quantitative and QualitativeDisclosuresAbout MarketRisk 57 ITEM8.FinancialStatements and Supplementary Data 57 ITEM9.Changes in and Disagreements with AccountantsonAccounting and FinancialDisclosure 57 ITEM 9A.Controlsand Procedures 57 ITEM9B. OtherInformation 58 PART III ITEM10. Directors, ExecutiveOfficers andCorporate Governance 58 ITEM11. Executive Compensation 58 ITEM12. SecurityOwnershipofCertainBeneficialOwners andManagement andRelated Stockholder Matters 59 ITEM13. Certain Relationships and Related Transactions, and Director Independence 60 ITEM14. PrincipalAccounting Fees andServices 60 PART IV ITEM 15.Exhibits, Financial Statement Schedules 61 ITEM16. Form 10-K Summary 61 SIGNATURES

(i) PART I

ITEM 1. Business

General

EOG Resources, Inc., aDelawarecorporation organizedin1985, togetherwith its subsidiaries (collectively,EOG), exploresfor,develops, produces and markets crude oil,natural gas liquids (NGLs) and natural gas primarily in major producing basins in the United StatesofAmerica(United StatesorU.S.),The RepublicofTrinidad and Tobago (Trinidad), The People's RepublicofChina (), the Sultanate of Oman(Oman) and, from time to time,selectother international areas. EOG's principalproducing areas arefurtherdescribed in "Exploration and Production" below. EOG'sAnnualReportsonForm 10-K, QuarterlyReports on Form 10-Q, Current Reports on Form 8-K and any amendments to those reports (includingrelated exhibits and supplemental schedules) filedorfurnished pursuant to Section13(a) or 15(d) of the SecuritiesExchange Actof 1934 (as amended) are made available,free of charge,through EOG'swebsite, as soon as reasonablypracticable after such reports havebeenfiled with,orfurnished to, the United States Securities and Exchange Commission (SEC). EOG'swebsite address is www.eogresources.com. Informationonour websiteisnot incorporated by reference into, and does not constitute a part of, thisreport.

At December31, 2020, EOG's total estimatednet proved reserves were 3,220 million barrelsofoil equivalent (MMBoe), of which 1,514 million barrels (MMBbl) were crudeoil and condensatereserves, 813 MMBbl were NGLs reserves and 5,360 billion cubicfeet(Bcf), or 893 MMBoe,werenatural gas reserves (see "Supplemental InformationtoConsolidated FinancialStatements"). At such date, approximately98% of EOG's net proved reserves, on acrude oil equivalentbasis, were located in the United States,1%inTrinidadand 1% in otherinternational areas. Crudeoil equivalent volumes are determined using aratio of 1.0 barrelofcrude oil and condensate or NGLs to 6.0thousandcubic feet(Mcf) of naturalgas.

EOG'soperations are all crude oil andnaturalgas explorationand production related. For information regarding the risks associated with EOG's domestic and foreign operations,see ITEM1A, Risk Factors.

EOG'sbusiness strategy is to maximizethe rateofreturn on investment of capital by controlling operatingand capital costsand maximizing reserve recoveries. Pursuant to thisstrategy,eachprospectivedrilling location is evaluatedbyits estimated rate of return. Thisstrategyisintended to enhancethe generation of cash flow and earnings from each unit of productiononacost-effective basis,allowingEOG to deliver long-term growth in shareholder value andmaintain astrong balance sheet. EOGisfocused on innovation and cost-effective utilizationofadvanced technology associated withthree- dimensional seismic andmicroseismic data, the developmentofreservoir simulation models, the use of improveddrilling equipment andcompletion technologies for horizontaldrilling and formation evaluation. These advanced technologiesare used, as appropriate,throughout EOG to reducethe risks and costs associated with allaspectsofoil and gas exploration, development and exploitation. EOG implementsits strategyprimarily by emphasizing the drillingofinternally generated prospects in order to find anddevelop low-cost reserves. Maintainingthe lowest possibleoperating cost structure,coupledwith efficient and safe operations and robust environmentalstewardship practices and performance, is integral in the implementation of EOG's strategy.

With respect to informationonEOG's working interest in wellsoracreage,"net" oil and gas wells or acreage are determinedbymultiplying "gross" oiland gas wellsoracreage by EOG'sworking interest in thewells or acreage.

Exploration and Production

UnitedStatesOperations

EOG's operations are locatedinmost of the productive basins in the United States with afocus on crudeoil and, to a lesserextent,liquids-rich natural gasplays.

At December 31, 2020, on acrude oilequivalent basis, 48% of EOG's net proved reserves in the United States were crude oiland condensate, 26% were NGLs and26% were natural gas.The majority of these reservesare in long-lived fields withwell-established production characteristics. EOG believesthatopportunitiesexist to increase productionthrough continued development in and aroundmanyofthese fields andthrough the utilizationofapplicable technologies. EOG also maintains an active exploration program designedtoextendfields and add new trends andresourceplays to its already broad portfolio.

1 Thefollowing is asummary of significant developments during 2020 andanticipated 2021 plans forcertain areas of EOG'sUnitedStates operations.

2020 2021 Crude Oil& Natural Gas Condensate Liquids Natural Gas Total Net Expected Net Volumes Volumes Volumes Acres (in Net Well Well AreaofOperation (MBbld) (1) (MBbld) (1) (MMcfd) (1) thousands) Completions Completions

South Texas162 33 281 1,138 223 160 Basin183 75 460 404 247 275 Rocky Mountain4914159 1,167 56 50 Mid-Continent 10 14 87 310 15 <5 OtherAreas4—53851 715 Total 408 136 1,040 3,870 548 ~500

(1) Thousand barrels perday or million cubicfeetper day,asapplicable.

The South Texasareaincludes our Eagle Ford playand our newlyannounced Dorado gas play. EOG holds approximately 516,000 total netacres in theprolificoil window of theEagle Ford andapproximately 163,000 netacres in the Dorado prospect area.During the second and third quarters of 2020,EOG significantly curtailedits Eagle Ford oil production due to low crude oilprices; operations in the EagleFordreturned to normal by the end of thethird quarterof2020. In the Dorado play, with the onset of the pandemicand resulting marketdownturn, EOG electedtodeferits 2020 drilling program and insteadfocus on gatheringand analyzing dataregarding the production performanceofits 2019 Dorado drilling program.In 2020, EOG completed213 netEagle Ford wellsand, late in 2020,acquiredand completed one netDoradowelltofurther delineatethe play. In 2021,EOG expectstocomplete approximately 145net EagleFordwells and to drill and complete approximately 15 netDorado wells.

In the DelawareBasin, EOGcompleted 247 net wells during2020, primarilyinthe DelawareBasin Wolfcamp, Bone Spring and Leonard plays. The DelawareBasin consistsofapproximately 4,800 feet of oil rich stackedpay potential offering EOG multiple co-developmentopportunities throughout its 404,000 total netacreage position.

In the Delaware BasinUpper Wolfcamp play, EOG hasapproximately226,000 netacres and completed166 netwells in 2020.EOG continuedits UpperWolfcampdevelopmentplanwithwellspacing as closeas500 feetinthe crude oil portion of the play and 880 feetinthe combinationcrude oil and natural gas portion. In additiontothe UpperWolfcamp, EOG completed 7net wells in 2020 in the newlyannounced MiddleWolfcampplayand has identified 193,000 net prospective acres. Continued improvement andexcellent resultsinthe Wolfcamp program were supportedbyoptimizedwell spacing, enhancedwell completions, precision drillingand continuedcost reductions. Moving forward into2021, the Delaware Basin Wolfcamp play willcontinue to be aprimary area of focus.

In the Bone Spring play, EOGhas three mainsub-plays: the First,Second andThird Bone Spring. In 2020, EOG completed 56 total netBone Spring wellswithin the threesub-plays on its combined289,000 netprospective acres. Of the three sub-plays,the Second Bone Spring had the majority of the activity in 2020 withEOG completing 42 net wells. The Bone Spring plays continue to be an integral part of EOG’sDelaware Basinplans and portfolio.

In the Leonard play, EOG holds approximately 160,000 netacres and maintainedits development planwith18net wells completed in 2020.With astrategy of developing deeper targets first while simultaneously collecting data from the shallowtargets, the Leonard play will progressively become amore active part of EOG’s program.

Activity in 2021 willremain focusedonthe DelawareBasin Wolfcamp, Bone Spring, and Leonard plays, where EOG expectstocomplete approximately 275 net wells.

2 Activity in theRocky Mountain area in 2020 was focusedonthe Wyoming PowderRiver Basin. In the PowderRiver Basin, EOG operatedaone-rigprogram andcompleted 35 netwells in theNiobrara, Mowry, Turnerand Parkmanformations. In addition, keyinfrastructurewas added in order to loweroperating costsand increase price realizations going forward. In the DJ Basin, EOG operated one rigfor apartial year and completed17net wells in both the Codell and theNiobrara formations. Activity in theDJBasin is expectedtobeminimal in 2021 as developmentcontinues to shifttothe PowderRiver Basin. In the Williston Basin, EOG completed 3net wells in theBakken and ThreeForks.In2020, production in the Rocky Mountain area and Williston Basin wassignificantly curtailed,primarilyinthe second quarter, in response to crude oilprice declines,but has subsequentlyreturnedtonormal levels.In2021, activitywillbefocused on development in the Powder RiverBasin withplans to complete approximately 45 net wells. EOG currently holds approximately1.2 million netacresinthe Rocky Mountainarea.

In the Mid-Continentarea, EOG continued its development of the Woodford OilWindow play with15net wells completed during 2020. EOGholdsapproximately 37,000 net acresinthe playand plans to have minimalactivity in 2021.

Operations Outside the United States

EOG has operations offshore Trinidad, in the China Sichuan Basin, Oman and in andisevaluating additional exploration, development andexploitation opportunities in theseand otherselect international areas.

Trinidad. EOG, through itssubsidiaries,including EOG Resources TrinidadLimited, holds interestsin(i) the exploration and production licenses covering the South East Coast Consortium (SECC)Block,Pelican and Banyan Fields, SercanAreaand each of their related facilitiesand the Ska, Mento, Reggaeand deep Teak, Saamanand Poui Areas, allof whichare offshore Trinidad; and(ii)aproduction sharingcontractwiththe Government of Trinidad and Tobago for each of the Modified U(a), ModifiedU(b) and4(a)Blocks.

Several fields in the SECC, Modified U(a), Modified U(b) and 4(a) Blocks, Banyan Field and Sercan Area have been developed andare producing natural gas andcrude oiland condensate.

In 2020,EOG's net production averagedapproximately180 MMcfdofnatural gasand approximately 1.0 MBbld of crude oiland condensate. In 2020, EOG drilled threenet wells and completed two netwells.The remaining netwell madea discovery thatisbeing evaluated.All wells discoveredcommercially economic reserves.

In 2021,EOG expectstofocus on the design and fabricationofthe platform and related infrastructure for the previouslyannounced discovery made in the ModifiedU(a)Block. In addition, EOG expects to continue its exploration program.

China.Since 2008,EOG has been developing the Baijaochang Field in the Chuan Zhong Blockexploration area in theSichuan Basin, SichuanProvince, China with its partner, PetroChina,under aproduction sharing contract.In2020, EOG's net production averaged approximately26MMcfd of natural gas.EOG continues to work withPetroChina to ensure uninterruptedproduction.

Oman.InSeptember 2020, EOG reached an agreement withAPEXOman(Block 36) Inc. to acquire itsentireinterest in Block 36 in Oman. TheRoyalDecree was issued on October 28, 2020 at whichpoint EOG became the operator and held all rightsunder the Exploration and Production Sharing Agreement for Block36. Additionally, in December 2020 the Ministry of Energy and Mineralsfor Omanapproved the assignment of Block49toEOG pursuant to the terms of the farm-in agreement withTethys OilMontasar Limited.Inaccordancewiththe terms of the farm-in agreement EOG participated in the drilling of an exploratory wellwhich wasinprogressatDecember 31, 2020. In 2021, EOG expects to drill twonet exploration wellsin Block 36.

Canada. EOG maintains approximately 47,000 net acres in theHorn River areainNortheast British Columbia. In March2020, EOGbeganthe process of exiting its Canada operations.

3 Marketing

In 2020, EOGcontinuedits diversified approach to marketing itswellheadcrude oiland condensate production. The majority of EOG'sUnited States wellhead crude oiland condensateproduction was transportedbypipelinetodownstream marketswith the remainder sold intolocal markets. MajorU.S.sales areas accessedbyEOG were at various locationsalong theU.S. GulfCoast, including Houston and Corpus Christi,Texas; Cushing,; thePermian Basin and theMidwest. In 2020, EOG also sold crude oilatthe Houston ShipChannel andthe Port of Corpus Christi for export to foreign destinations. In each case, the pricereceived was basedonmarketprices at thatspecificsales point or based on the priceindex applicablefor thatlocation. In 2021, the pricing mechanism for such production is expected to remainthe same. At December 31, 2020, EOG wascommitted to delivertomultiple parties fixedquantities of crude oil of 8MMBblsin2021, allofwhich is expected to be delivered from future production of available reserves.

In 2020, EOG processedcertainofits United Stateswellhead natural gasproduction, eitheratEOG-ownedfacilities or at third-party facilities, extractingNGLs. NGLs were soldatprevailing marketprices, intoeitherlocal markets or downstream locations. In certain instances, EOGexchangedits NGL production for purityproductsreceived downstream,whichweresold at prevailing marketprices. In 2021, suchpricing mechanisms areexpectedtoremainthe same.

In 2020, consistent with its diversified marketing strategy, the majority of EOG'sUnitedStates wellhead naturalgas production was transportedbypipeline to various locations, including Katy, Texas;EastTexas; theAguaDulceHub in South Texas;the Cheyenne Hub in Weld County, Colorado; Southern ;and Chicago, Illinois. Remaining natural gas production was sold intolocal markets. In each case, pricing was basedonthe spot market priceatthe ultimatesales point. In 2021,the pricing mechanism for suchproduction is expected to remainthe same. Additionally, EOGsells natural gastoa liquefied natural gasliquefactionfacilitynearCorpus Christi, Texas, and receivespricing based on the Platts Japan Korea Marker. At December 31, 2020, EOG wascommitted to deliver to multipleparties fixed quantities of naturalgas of 170 Bcfin 2021, 105 Bcfin2022, 91 Bcfin2023, 94 Bcfin2024, 81 Bcfin2025and 1,609 Bcfthereafter, allofwhich is expected to be deliveredfrom future production of available reserves.

In 2020, amajority of the wellheadnatural gas volumes from Trinidad were soldunder contracts withpriceswhich were either wholly or partially dependent on Caribbean ammoniaindex pricesand/ormethanol prices. Theremaining volumes were sold under acontract at prices partially dependent on UnitedStates Henry Hub marketpricesorunder afixed price contract.In2021, natural gasvolumesfromTrinidad will be sold underafixedpricecontract ending in 2026.

In 2020, allwellhead natural gasvolumes from China were soldatregulated prices based on the purchaser's pipeline salesvolumes to various local market segments. Thepricing mechanism for production in China is expectedtoremain the samein2021.

In certain instances, EOG purchasesand sells third-partycrude oiland natural gas in ordertobalancefirm transportation capacity with production in certainareasand to utilize excess capacity at EOG-ownedfacilities.

4 During 2020, three purchasers each accounted formore than 10%ofEOG's total wellhead crude oil andcondensate, NGLs andnaturalgas revenuesand gathering, processing and marketing revenues. Thethree purchasers are in the crude oil refining industry. EOG does not believe thatthe lossofany singlepurchaser would have amaterially adverse effectonits financial condition or resultsofoperations.

Wellhead Volumes and Prices

The following table setsforth certain information regarding EOG's wellhead volumes of, and average prices for, crude oil andcondensate,NGLsand natural gas. The tablealso presentscrude oil equivalent volumes which are determined usinga ratio of 1.0 barrelofcrude oiland condensate or NGLsto6.0 Mcf of natural gasfor each of the yearsended December 31, 2020, 2019 and 2018. See ITEM 7, Management's Discussion and AnalysisofFinancial Condition and Results of Operations - Results of Operations, for wellhead volumesonaper-daybasis.

Year EndedDecember31202020192018

CrudeOil and Condensate Volumes(MMBbl) (1) UnitedStates: Eagle Ford 54.6 68.3 62.4 Delaware Basin 67.0 63.4 46.3 Other 27.8 34.6 35.4 UnitedStates149.4 166.3 144.1 Trinidad 0.4 0.2 0.3 OtherInternational (2) — 0.1 1.6 Total 149.8 166.6 146.0 NaturalGas LiquidsVolumes (MMBbl) (1) UnitedStates: Eagle Ford 9.7 10.7 11.4 Delaware Basin 27.7 23.5 15.8 Other 12.4 14.7 15.3 United States 49.8 48.9 42.5 OtherInternational (2) — —— Total 49.8 48.9 42.5 NaturalGas Volumes(Bcf) (1) UnitedStates: EagleFord 53 53 58 Delaware Basin 168 147 110 Other 160 190 169 UnitedStates 381 390 337 Trinidad 66 95 97 OtherInternational (2) 11 14 11 Total 458 499 445 CrudeOil Equivalent Volumes (MMBoe) (3) UnitedStates: EagleFord 73.1 87.8 83.5 Delaware Basin 122.7 111.4 80.3 Other 66.9 81.0 78.8 UnitedStates 262.7 280.2 242.6 Trinidad 11.4 16.0 16.5 OtherInternational (2) 1.8 2.4 3.4 Total 275.9 298.6 262.5

5 Year EndedDecember 31 2020 2019 2018

Average Crude Oiland CondensatePrices($/Bbl) (4) UnitedStates $38.65 $57.74 $65.16 Trinidad 30.2047.16 57.26 OtherInternational (2) 43.0857.40 71.45 Composite 38.63 57.72 65.21 Average NaturalGas Liquids Prices($/Bbl) (4) UnitedStates $13.41 $16.03 $26.60 OtherInternational (2) — —— Composite 13.41 16.03 26.60 Average NaturalGas Prices($/Mcf) (4) UnitedStates $1.61$2.22 $2.88 Trinidad 2.57 2.72 2.94 OtherInternational (2) 4.66 4.44 4.08 Composite 1.83 2.38 2.92

(1) Millionbarrels or billion cubic feet, as applicable. (2) OtherInternational includes EOG's UnitedKingdom, China and Canada operations. TheUnitedKingdomoperations were soldinthe fourth quarterof2018. (3) Millionbarrels of oilequivalent; includescrude oiland condensate, NGLs and natural gas. (4) Dollars per barrel or per thousand cubic feet, as applicable.Excludes the impact of financial commodity derivative instruments (see Note 12 to Consolidated Financial Statements).

Human CapitalManagement

As of December31, 2020, EOG employed approximately2,900 persons, including foreign national employees. EOG'sapproach to human capital management includes oversight by the and Compensation Committeeand focuses on variousareas,including the following:

Culture;Recruiting; Retention. EOG's unique culture is keytoits sustainable success. By providing employees with a quality environment in which to work, and by maintaining aconsistent collegerecruiting and internship program, EOG is able to attract andretainsomeofthe industry's best andbrightest. To help assess the effectivenessofits approach to humancapital management, EOG conducts an annualemployeeengagement survey. Based on theresults of thesurvey, EOGhas received "top workplace" recognition in various office locations.

Compensation, Benefits, Health &Wellness.EOG placesahigh levelofimportance on attracting and retainingtop talent, by providing competitive salaries,bonuses andasubsidized, comprehensive benefits package.EOG also offers a holisticwellness program, amatching gifts program, aflexiblework schedule, paidfamily care leave,paid leavefor illness or injury andanemployeeassistance program to supportthe mentalwell-beingofemployees andtheir dependents. In addition, with new-hire stockgrantsand an annualstock grantprogram,every employee is aparticipant in EOG'ssuccess.

In 2020, in responsetothe COVID-19 pandemic, EOG focused on keeping its employees andtheir families safe, including providing technologyand support to employees enabling them to work productively from home.Inaddition, at its offices and work sites, EOGhas instituted social distancingpractices andprotocols andhas providedmasks,hand sanitizerand additional cleaning.

Training and Development.EOG providestraining in leadership, management skills, communication, team effectiveness, technical skills and development anduse of EOG systemsand applications.EOG's leadership training is focused on providing continuity of leadershipatEOG by developing the skills neededtolead amulti-disciplined, diverse and decentralized workforce.Inaddition, EOG holds several internal technical conferenceseach year designed to sharebest practices andtechnicaladvancesacross the company, including safety and environmental topics.EOG also offers its employees atuition reimbursement program as well as reimbursementfor the costofprofessionalcertification.

6 Diversityand Inclusion.Gender, racial, ethnic andculturaldiversity, and diversityinbackground andexperience, leadstodiversityofthought, which is atremendousasset and is actively embraced by EOG. As reflectedinits Code of Business Conductand Ethicsfor Directors, Officersand Employees, EOG is committedtoproviding equal opportunity in all aspectsofemployment and to hiring, evaluating and promoting employees basedonskills and performance. EOG's collaborative culture fosters inclusivenessatall levels of thecompany. Further, EOG focusesondeveloping itsemployees, including those withdiverse backgrounds, to allow forcareeropportunities,including promotion into supervisory and management positions.

Safety.EOG'ssafety management programsand processesare centered on aperformance-basedphilosophy,pursuant to whichEOG sets safetyexpectations and provides aframework within which management canachieve andassess safety performanceinasystematic way. EOG'ssafety performanceisalsoconsideredinevaluating employee performance and compensation. EOG provides initial, periodicand refreshersafety training to employees as well as to contractors and others who maywork at or visitEOG's facilities.These training programsaddress various topics, including operating procedures, safe work practicesand emergencyand incident response procedures.

Competition

EOG competeswithmajor integrated oil andgas companies,government-affiliated oil andgas companies and other independent oiland gas companies forthe acquisitionoflicenses and leases,properties and reserves and access to the facilities, equipment,materials, services, and employees and otherpersonnel(includinggeologists, geophysicists, engineers and other specialists) requiredtoexplore for, develop,produce,marketand transport crudeoil,NGLsand naturalgas. CertainofEOG's competitors have financial andother resources substantiallygreater thanthose EOGpossesses andhave establishedstrategic long-term positions or strong governmental relationships in countriesorareasinwhich EOG mayseek new or expanded entry. As aconsequence, EOG maybeatacompetitive disadvantage in certain respects, suchasinbidding for drilling rightsorin accessing necessary services, facilities, equipment, materialsand personnel.Inaddition,EOG's larger competitors mayhavea competitive advantage when responding to factors thataffect demandfor crude oil, NGLs and natural gas, such as changing worldwide prices andlevels of production and the cost and availabilityofalternative fuels. EOG also faces competition from competing energy sources, suchasrenewableenergy sources. SeeITEM1A, Risk Factors.

Regulation

2020 Election.InNovember2020, Joseph R. Biden Jr. was elected President of the United States.New or revised rules, regulations and policies maybeissued, and newlegislation may be proposed, during the current administration thatcould impactthe oiland gasexploration and production industry. Such rules, regulations, policiesand legislation may affect, among otherthings, (i) permitting for oil andgas drilling on federal lands, (ii)the leasingoffederal landsfor oiland gasdevelopment, (iii) theregulationofgreenhouse gas(GHG) emissionsand/or otherclimate change-related matters associated withoil and gas operations, (iv) the use of hydraulic fracturing on federal lands, (v)the calculationofroyalty paymentsinrespect of oil andgas production from federal landsand (vi) U.S. federalincometax laws applicable to oil andgas explorationand production companies.See thebelow discussion and ITEM 1A, RiskFactors, for additional information.

United States Regulation of Crude Oiland Natural Gas Production. Crude oiland natural gasproduction operations are subject to various types of regulation, includingregulation by federal andstate agencies.

United States legislationaffecting the oiland gas industry is under constant review foramendment or expansion. In addition, numerous departments andagencies, both federaland state, are authorized by statutetoissue, and have issued, rules and regulations applicabletothe oiland gas industry. Suchrules and regulations, among otherthings, require permits for the drilling of wells, regulate the spacing of wells, prevent the waste of natural gas through restrictionsonflaring, require surety bonds for various exploration and production operations and regulatethe calculationand disbursement of royalty payments (for federal and state leases), production taxesand ad valorem taxes.

Aportion of EOG's oil and gas leases in NewMexico, North Dakota, Utah, Wyoming andthe GulfofMexico, as well as in other areas, are granted by thefederalgovernmentand administered by theBureau of Land Management (BLM)and/or the Bureau of IndianAffairs (BIA) or, in thecase of offshore leases (which, for EOG, aredeminimis), by theBureauofOcean Energy Management (BOEM) and the Bureau of Safety and EnvironmentalEnforcement (BSEE), allfederalagencies. Operations conductedbyEOG on federaloil and gas leases must complywithnumerous additional statutory andregulatory restrictions and, in the case of leases relating to tribal lands, certain tribalenvironmental and permitting requirementsand employment rightsregulations. In addition, the U.S. Department of the Interior (via various of itsagencies, including the BLM, the BIAand the OfficeofNaturalResourcesRevenue) hascertain authorityover our calculationand payment of royalties, bonuses, fines, penalties, assessments and otherrevenuesrelatedtoour federal and tribal oiland gasleases.

7 BLM, BIA and BOEM leasescontain relativelystandardized termsrequiring compliancewith detailed regulations and, in the case of offshore leases,orderspursuant to the Outer Continental Shelf Lands Act (which are subjecttochangebythe BOEMorBSEE). Under certain circumstances, the BLM, BIA, BOEM or BSEE(as applicable) may require operations on federal leases to be suspendedorterminated. Any suchsuspension or termination couldmaterially and adversely affect EOG's interests on federal lands. Further, on January 27, 2021, President BidenissuedExecutive Order14008 entitled "Tackling the Climate CrisisatHome andAbroad," directing the Secretaryofthe Interior, to the extent consistentwith applicable law andin consultationwithother agencies and stakeholders, to, among otherthings,pauseapproval of new oil andnatural gasleaseson federal lands or in offshore waterspending completion of acomprehensive review andreconsideration of federaloil andgas permitting and leasing practices. Any limitationorban on permitting for oil and gas exploration and production activitieson federal lands could have amaterial and adverse effect on EOG'soperations, financial condition and resultsofoperations.

The transportation and sale for resale of natural gasininterstatecommerce are regulated pursuant to the NaturalGas Act of 1938, as amended (NGA),and theNatural Gas Policy Act of 1978. These statutes are administeredbythe Federal Energy RegulatoryCommission (FERC). Effective January1993, the Natural Gas Wellhead DecontrolAct of 1989 deregulated naturalgas prices for all"first sales" of natural gas, which includes allsales by EOG of itsown production. All othersales of naturalgas by EOG, suchasthose of natural gaspurchased from third parties, remainjurisdictional sales subject to ablanket sales certificate under the NGA, whichhas flexible terms and conditions.Consequently, allofEOG's sales of natural gas currentlymay be made at marketprices, subjecttoapplicable contractprovisions. EOG'sjurisdictional sales, however, maybesubject in thefuture to greater federaloversight,including the possibility that theFERC might prospectively imposemore restrictive conditions on such sales. Conversely, sales of crude oil andcondensateand NGLs by EOG are made at unregulated marketprices.

EOG owns certain gathering and/or processing facilitiesinthe Permian Basin in West Texasand ,the Fort WorthBasinBarnett Shale in North Texas, the WillistonBasin Bakkenand ThreeForks playsinNorth Dakota, andthe Eagle Ford in South Texas. State regulation of gathering and processing facilitiesgenerallyincludes various safety, environmental and, in some circumstances, nondiscrimination requirements with respect to the provision of gathering and processing services, but does not generallyentailrateregulation. EOG'sgathering andprocessing operations couldbe materiallyand adversely affected should theybesubject in thefuture to the applicationofstate or federal regulation of rates and services.

EOG'sgatheringand processing operations also maybe, or become, subjecttosafety andoperationalregulations relating to the design, installation, testing, construction, operation, replacement and management of suchfacilities. Additional rulesand legislationpertaining to these mattersare considered and/or adopted from time to time.Although EOG cannot predict what effect, if any,such legislation might haveonits operationsand financial condition,EOG couldberequired to incur additional capitalexpenditures and increased compliance and operating costsdependingonthe nature and extent of such future legislative andregulatory changes.

EOG also owns crude oilrail loading facilities in North Dakotaand crudeoil truck unloading facilities in certain of its U.S. plays. Regulation of such facilities is conducted at the state andfederal levels andgenerallyincludesvarious safety, environmental,permitting andpackaging/labeling requirements. Additionalregulation pertaining to these mattersisconsidered and/or adopted from time to time. Although EOG cannot predict what effect,ifany, any such new regulations might have on itscrude-by-rail assetsand the transportation of its crude oilproductionbytruck,EOG couldberequired to incur additional capitalexpenditures andincreased complianceand operatingcostsdependingonthe nature and extent of such future regulatory changes. EOGdid not transport any crude oilbyrailduring 2020.

Proposalsand proceedings thatmight affect the oiland gasindustry are consideredfromtime to time by Congress, the statelegislatures, theFERC and other federal, stateand local regulatorycommissions, agencies, councils and courts. EOG cannot predict when or whether any suchproposals or proceedings maybecomeeffective.Itshouldalsobenoted thatthe oil and gasindustry historically hasbeenveryheavily regulated;therefore, there is no assurance thatthe approach currentlybeing followedbysuchlegislative bodiesand regulatorycommissions, agencies, councilsand courts will remain unchanged.

Environmental Regulation Generally-United States. EOGissubject to various federal,state and local laws and regulations covering the discharge of materials intothe environment or otherwise relating to theprotection of the environment. These laws and regulations affectEOG's operationsand costsasaresultoftheir effect on crudeoil andnatural gasexploration, development andproduction operations. Failure to complywiththese lawsand regulations may resultinthe assessment of administrative,civil andcriminalpenalties,including the assessment of monetary penalties, the impositionofinvestigatory and remedial obligations, the suspension or revocation of necessary permits,licenses and authorizations,the requirement that additional pollution controls be installed and the issuanceoforders enjoining future operations or imposing additional compliance requirements.

8 In addition, EOG has acquired certain oiland gaspropertiesfromthird parties whose actions withrespecttothe management anddisposal or release of hydrocarbons or otherwastes were not underEOG's control. Under environmental laws andregulations, EOG couldberequiredtoremove or remediatewastes disposed of or released by prior owners or operators. EOG also could incur costs related to the clean-up of third-partysites to whichitsentregulated substances for disposalorto whichitsentequipment for cleaning, and for damages to natural resourcesorother claims relatedtoreleasesofregulated substances at suchthird-party sites. In addition,EOG couldberesponsible underenvironmental lawsand regulationsfor oil and gas properties in which EOGpreviouslyowned or currentlyowns an interest,but wasorisnot the operator. Moreover, EOG is subject to theU.S. Environmental Protection Agency's (U.S. EPA) rulerequiring annual reportingofGHG emissions and, as discussed furtherbelow, is also subject to federal, state and local laws and regulationsregarding hydraulic fracturing andotheraspects of our operations.

Compliancewithenvironmental laws and regulationsincreases EOG'soverall cost of business, but has not had, to date, amaterialadverse effect on EOG's operations, financial conditionorresultsofoperations. In addition, it is not anticipated,based on current laws and regulations,thatEOG will be requiredinthe nearfuturetoexpend amounts (whether for environmental control facilitiesorotherwise) thatare material in relationtoits total exploration and development expenditure program in order to comply withsuchlawsand regulations. However, giventhatsuchlawsand regulations aresubjectto change, EOGisunabletopredictthe ultimate cost of complianceorthe ultimate effect on EOG's operations, financialcondition and resultsofoperations.

Climate Change -UnitedStates. Local, state,federal andinternationalregulatory bodies have been increasingly focusedonGHG emissions and climatechange issuesinrecent years. In additiontothe U.S. EPA's rule requiring annual reporting of GHG emissions,the U.S. EPA hasadopted regulations for certain large sourcesregulating GHG emissions as pollutants underthe federal Clean AirAct. Further, the U.S. EPA, in May2016, issuedregulations thatrequire operatorsto reducemethane emissions and emissions of volatile organic compounds (VOC) from new, modifiedand reconstructed crude oil andnatural gaswells and equipmentlocated at natural gas production gathering and boosterstations, gas processing plants and natural gastransmissioncompressor stations. In September 2020,the U.S. EPA issued afinal rule that removed the transmission and storage segment from the 2016 new source performance standards, rescinded VOC and methane emissions standards for the transmission and storagesegment andrescinded methane emissionsstandards for the production and processing segments. Various states and industry and environmental groups are separatelychallenging the U.S. EPA's 2016 standards and its September 2020 finalrule.Notwithstanding the current court challenges, the U.S. EPAunder the Biden Administration mayreconsider the September2020 finalrule, whichcould resultinmore stringent methane emission rulemaking.

At the international level, theU.S., in December2015, participatedinthe 21st Conferenceofthe Parties of the United Nations Framework Convention on Climate Change in Paris, France. The Paris Agreement (adoptedatthe conference) calls for nations to undertake efforts withrespecttoglobaltemperaturesand GHG emissions. TheParis Agreement went intoeffect on November 4, 2016. While theU.S. withdrew from the Paris Agreement on November4,2020, President Bidenissued an executive order on January 20, 2021 recommitting the United States to theParis Agreement. In addition, many state andlocal officials have stated their intenttointensifyeffortstoupholdthe commitments setforth in theinternational accord. Further, on January 27, 2021, President Bidenissued Executive Order 14008 entitled "Tacklingthe Climate Crisis at Home andAbroad," directing the Secretaryofthe Interior, to theextent consistent with applicable law and in consultationwithother agenciesand stakeholders, to, among other things, considerwhether to adjust royaltiesassociated withoil andgas resources extractedfrom federal lands and offshore waterstoaccount for corresponding climatecosts.

EOG believes that its strategytoreduceGHG emissions throughout itsoperations is both in the best interest of the environment andaprudent business practice. EOGhas developedasystem thatisutilizedincalculatingGHG emissions from itsoperating facilities. This emissionsmanagementsystemcalculatesemissions basedonrecognized regulatory methodologies, where applicable, and on commonlyaccepted engineering practices. EOGreportsGHG emissions for facilities covered under the U.S. EPA's Mandatory Reporting of Greenhouse GasesRulepublishedin2009, as amended.

EOG is unabletopredictthe timing,scope andeffect of any currentlyproposed or future investigations, laws, regulations, treaties or policies regarding climate change andGHG emissions (including any lawsand regulations thatmay be enactedinthe U.S. by the new administration),but the directand indirectcostsofsuchdevelopments (if enacted, issuedor applied) couldmaterially andadversely affectEOG's operations, financial condition and results of operations. Further, the increasing attention to globalclimatechange risks has created the potential for agreater likelihood of governmental investigations and privateand public litigation,whichcouldincrease our costsorotherwise adversely affect our business.

9 RegulationofHydraulicFracturingand Other Operations -United States. Substantially allofthe onshore crude oil and naturalgas wells drilled by EOG are completed andstimulatedthrough the useofhydraulicfracturing. Hydraulic fracturing technology, which has beenused by the oiland gasindustry formore than60years and is constantlybeing enhanced, enablesEOG to produce crude oiland natural gas that otherwise would not be recovered. Specifically,hydraulicfracturingisa process in which pressurized fluidispumpedintounderground formations to create tinyfractures or spaces thatallow crude oil and naturalgas to flow from the reservoirinto the well so that it can be brought to the surface. Hydraulicfracturinggenerally takes place thousands of feet underground, aconsiderable distance below anydrinking wateraquifers, and there are impermeable layers of rock between the areafractured andthe water aquifers. Themakeup of thefluid used in thehydraulic fracturing process typically includes water and sand, and less than1%ofhighlydilutedchemicaladditives; lists of thechemical additives used in fracturing fluids are available to the public via internetwebsites and in other publications sponsoredby industry trade associations and through state agencies in those states that require the reportingofthe components of fracturing fluids. While themajority of thesand remainsunderground to holdopenthe fractures, asignificant amount of thewater and chemicaladditives flow backand are then eitherreusedorsafely disposedofatsites thatare approved and permittedbythe appropriateregulatory authorities.EOG periodicallyconducts regulatoryassessmentsofthese disposal facilities to monitor compliancewith applicable regulations.

The regulation of hydraulic fracturing is primarily conductedatthe state andlocal level through permittingand other compliancerequirements. In April 2012, however, the U.S. EPA issuedregulations specifically applicabletothe oiland gas industry that requireoperatorstosignificantly reduceVOC emissionsfromnatural gaswells that are hydraulically fractured through the use of "greencompletions"tocapture natural gasthat would otherwise escape intothe air.The U.S. EPA has also issued regulationsthat establish standards for VOC emissions from severaltypes of equipment,including storage tanks, compressors, dehydrators, and valves andsweetening units at gasprocessing plants.Inaddition, in May 2016, the U.S. EPA issuedregulationsthatrequire operatorstoreducemethane andVOC emissions from new, modifiedand reconstructed crude oil andnatural gaswells and equipmentlocated at natural gas production gathering and boosterstations, gas processing plants and natural gastransmission compressor stations. In September2020, the U.S. EPA issuedamendmentstothe 2012 and 2016 new source performance standards, which removed the transmissionand storage segmentfromthe new sourceperformance standards, rescinded VOC andmethane emissionsstandards for the transmissionand storage segment, andrescinded methane emissions standards for the production and processing segments.

From time to time,there have beenvarious other proposalstoregulate hydraulic fracturing at the federal level. In addition, there were proposalsand positions taken by President Bidenduringhis campaign regarding the use of hydraulic fracturing on federallands and waters. Further, on January27, 2021, President BidenissuedExecutive Order14008 entitled "Tackling theClimateCrisis at Home and Abroad,"directing the Secretary of theInterior, to the extent consistent with applicable law and in consultationwithother agencies and stakeholders, to, among other things, pause approval of new oil and natural gasleases on federallands or in offshore waterspending completion of acomprehensive reviewand reconsideration of federaloil andgas permitting and leasing practices.

In addition to the above-described federal regulations, somestateand local governments haveimposed, or have considered imposing, various conditions and restrictions on drilling andcompletion operations, including requirements regarding casing andcementing of wells;testingofnearby water wells; restrictions on access to, andusage of, water; disclosure of the chemicaladditivesusedinhydraulicfracturing operations; restrictions on the type of chemicaladditives thatmay be used in hydraulic fracturing operations; and restrictions on drilling or injection activities on certain lands lying within wilderness wetlands, ecologicallyorseismically sensitive areas, and other protected areas.Such federal,state and local permittingand disclosure requirements,operating restrictions, conditions or prohibitioncouldlead to operational delays and increased operating and compliance costs and, moreover, could delay or effectivelyprevent the development of crude oil andnatural gas from formationswhich wouldnot be economicallyviable without the useofhydraulic fracturing.

Compliancewithlaws and regulations relating to hydraulicfracturing and other aspects of our operations increases EOG's overall cost of business, but hasnot had, to date, amaterialadverse effect on EOG's operations, financialcondition or resultsofoperations. In addition, it is not anticipated, based on current lawsand regulations, thatEOG willberequired in the near futuretoexpend amounts thatare materialinrelation to its totalexploration anddevelopment expenditure program in order to complywithsuchlawsand regulations. However, EOG is unabletopredict (i)the timing, scope andeffect of any currentlyproposedorfuture lawsorregulations regarding hydraulic fracturinginthe United States or otheraspectsofour operations and (ii)the ultimatecost of complianceorthe ultimateeffect on EOG's operations, financial condition and results of operations relating to suchfuture laws and regulations.The direct andindirect costs of suchlawsand regulations (if enacted) could materially andadverselyaffect EOG'soperations,financial conditionand results of operations.

10 OtherInternational Regulation. EOG'sexploration andproduction operations outside the United States aresubjectto various types of regulations, including environmental regulations, imposed by the respective governmentsofthe countriesin whichEOG's operationsare conducted, andmay affect EOG'soperations and costsofcompliance withinthose countries. EOG currentlyhas operations in Trinidad, China and Canada,and an exploration program in Oman. EOG is unabletopredict the timing, scopeand effect of any currently proposed or future laws, regulationsortreaties,including those regarding climate change and hydraulicfracturing, but the directand indirect costsofsuchlaws, regulations and treaties(if enacted) could materially and adversely affect EOG'soperations, financialcondition andresults of operations. EOGwillcontinue to review the risks to its businessand operations outsidethe United Statesassociated withall environmental matters, including climate change and hydraulic fracturing regulation. In addition, EOG will continue to monitor and assess any newpolicies,legislation, regulations and treaties in the areas outside the United States where it operates to determinethe impact on itsoperations and take appropriateactions, where necessary.

OtherRegulation. EOG has sand mining and processing operations in Texas andWisconsin, which support EOG's exploration and development operations.EOG's sand mining operations are subject to regulation by thefederal MineSafety and Health Administration (in respect of safety and healthmatters) and by stateagencies (in respect of airpermitting andother environmental matters).The information concerning mine safety violations and otherregulatory matters requiredbySection 1503(a)ofthe Dodd-FrankWallStreet Reformand Consumer ProtectionAct and Item104 of Regulation S-K (17 CFR 229.104) is included in Exhibit 95 to thisreport.

For additional discussion regarding the regulatory-relatedrisks to whichEOG's operations, financial condition and results of operations areormay be subject,see ITEM 1A, Risk Factors.

OtherMatters

Energy Prices. EOG is acrude oiland natural gasproducerand is impacted by changes in the prices for crude oiland condensate, NGLs and naturalgas. During the lastthreeyears, average United Statescommodity priceshave fluctuated, at timesrather dramatically. Averagecrude oiland condensate pricesreceivedbyEOG forproduction in the UnitedStates decreased33% in 2020 and 11% in 2019 and increased 28% in 2018, each as comparedtothe immediately preceding year. EOG'squarterly price realizationsrangedfrom$20.40per barrelto$46.97per barrel in 2020.Average NGL prices received by EOG for production in the United Statesdecreased 16% in 2020 and 40% in 2019 andincreased 18% in 2018,eachas compared to the immediately preceding year. These fluctuations resulted in a27% decrease in theaverage wellheadnatural gas price receivedbyEOG forproduction in the United States in 2020, a23% decrease in 2019, and a31% increase (inclusiveofa positive revenueadjustment of $0.44 perMcf related to theadoption of Accounting Standards Update 2014-09) in 2018, each as compared to theimmediately preceding year.

Due to the many uncertainties associatedwiththe world political andeconomic environment (for example, the actions of other crude oilexportingnations, including the Organization of Exporting Countries, and the duration and impact of the ongoingCOVID-19 pandemic), the global supply of, and demand for, crude oil, NGLs andnaturalgas and the availabilityofother energy supplies, the relativecompetitiverelationshipsofthe various energy sourcesinthe view of consumersand otherfactors, EOG is unabletopredict whatchanges mayoccur in the prices of crude oiland condensate,NGLs and natural gasinthe future. For additional discussion regarding changes in crude oil andcondensate, NGLs andnaturalgas prices andthe risks that such changes maypresent to EOG, see ITEM1A, RiskFactors.

Including the impactofEOG's crude oiland NGL derivativecontracts (exclusive of basisswaps) andbased on EOG's taxposition,EOG's price sensitivity in 2021 for each $1.00 per barrelincrease or decrease in wellhead crude oiland condensate price, combined withthe estimatedchange in NGL price, is approximately $99 million for net incomeand $127 million for pretax cash flows from operating activities. Including the impact of EOG's natural gas derivative contractsand based on EOG's taxposition andthe portion of EOG'santicipated naturalgas volumes for 2021 for which priceshave not beendetermined under long-term marketing contracts, EOG's pricesensitivity for each $0.10 per Mcf increase or decrease in wellheadnaturalgas price is approximately $31 million for net incomeand $40millionfor pretaxcash flows from operatingactivities. For asummary of EOG's financialcommodityderivative contractsthrough February 18, 2021, see ITEM 7, Management's Discussion and Analysis of Financial Condition andResults of Operations -Capital Resourcesand Liquidity -Commodity Derivative Transactions. For asummary of EOG's financial commodity derivative contracts for the twelve months ended December 31, 2020, see Note 12 to Consolidated Financial Statements.

11 RiskManagement. EOG engagesinprice risk managementactivitiesfrom time to time.These activities are intended to manage EOG'sexposure to fluctuations in prices of crude oil, NGLs and natural gas. EOG utilizesfinancialcommodity derivative instruments, primarily priceswap, option, swaption,collar and basisswapcontracts, as ameanstomanagethis price risk. See Note 12 to ConsolidatedFinancialStatements. Forasummary of EOG's financial commodity derivative contracts through February 18, 2021, see ITEM 7, Management'sDiscussionand AnalysisofFinancialConditionand Resultsof Operations - Capital Resourcesand Liquidity-Commodity Derivative Transactions.

All of EOG's crude oil, NGL and naturalgas activities are subjecttothe risks normally incident to theexplorationfor, and development, production and transportation of,crude oil,NGL and natural gas, includingrig andwell explosions, cratering, fires, loss of wellcontrol and leaks andspills, each of which couldresult in damage to life, property and/or the environment. EOG'soperations arealso subject to certain perils, including hurricanes, flooding and otheradverse weatherevents. Moreover, EOG'sactivities are subject to governmentalregulations as well as interruption or termination by governmentalauthorities based on environmental andother considerations. Lossesand liabilitiesarising from suchevents couldreduce EOG'srevenues and increase costs to EOG to theextent not covered by insurance.

Insurance is maintained by EOG against some, but not all, of these risksinaccordance with what EOG believesare customary industry practices and in amounts and at costs thatEOG believestobeprudent and commercially practicable. Specifically,EOG maintains commercial general liability and excess liabilitycoverageprovided by third-partyinsurers for bodilyinjury or death claims resulting from an incident involving EOG's operations (subject to policyterms and conditions). Moreover, in the eventanincident involving EOG's operationsresults in negative environmental effects, EOG maintains operators extra expense coverage providedbythird-party insurers for obligations, expenses or claimsthatEOG mayincur from such an incident, including obligations, expenses or claimsinrespect of seepage andpollution,cleanupand containment, evacuation expenses and control of the well (subject to policy terms and conditions). In theevent of awell control incident resulting in negativeenvironmental effects, such operators extra expense coverage would be EOG's primarycoverage, withthe commercial general liability andexcess liability coverage referenced above alsoproviding certain coverage to EOG. Allof EOG's drilling activities are conducted on acontractualbasis with independentdrilling contractors andother third-partyservice contractors. The indemnificationand other risk allocation provisions included in suchcontracts are negotiatedonacontract-by- contract basis andare eachbasedonthe particular circumstancesofthe servicesbeing providedand theanticipated operations.

In addition to the above-described risks, EOG's operationsoutside the United Statesare subjecttocertain risks, including the riskofincreases in taxes and governmental royalties, changesinlaws and policies governing the operations of foreign-based companies, expropriation of assets, unilateral or forcedrenegotiation, modification or nullification of existing contractswithgovernmental entities,currency restrictions andexchange ratefluctuations. Please refer to ITEM 1A, Risk Factors,for further discussion of the risks to whichEOG is subjectwithrespect to its operationsoutside the United States.

Information About Our Executive Officers

The current executive officersofEOG andtheirnames andages (as of February 25, 2021) areasfollows:

Name Age Position

WilliamR.Thomas 68 Chairman of the Board andChiefExecutive Officer

Lloyd W. Helms, Jr. 63 Chief Operating Officer

Ezra Y. Yacob44President

KennethW.Boedeker58Executive Vice President,Explorationand Production

Timothy K. Driggers 59 Executive Vice President andChief Financial Officer

Michael P. Donaldson 58 Executive Vice President,General Counseland Corporate Secretary

12 William R. Thomaswas electedChairman of theBoard and Chief Executive Officer effective January 2014.Hewas elected SeniorVicePresident andGeneral ManagerofEOG's Fort Worth,Texas, office in June 2004,Executive VicePresident and General Manager of EOG's Fort Worth, Texas, officeinFebruary 2007 and Senior Executive Vice President, Exploitation in February 2011. He subsequently served as Senior Executive Vice President, ExplorationfromJuly2011toSeptember2011, as President from September 2011 to July 2013 and as President and ChiefExecutive Officer from July 2013 to December 2013. Mr. Thomas joinedapredecessor of EOGinJanuary 1979. Mr. ThomasisEOG's principal executive officer.

Lloyd W. Helms, Jr. was elected Chief Operating Officer in December 2017. Prior to that, he served as Executive VicePresident,Exploration and Production from August 2013 to December2017. He was elected Vice President,Engineering and AcquisitionsinSeptember2006, VicePresident andGeneralManagerofEOG's Calgary, Alberta,Canada officeinMarch 2008,and served as Executive Vice President, Operations fromFebruary 2012 to August 2013. Mr.Helms joined a predecessor of EOGinFebruary1981.

Ezra Y. Yacob waselected President effective January 2021. Prior to that, he servedasExecutive Vice President, Exploration and Production from December 2017 to January 2021 and as VicePresident andGeneralManager of EOG's Midland, Texas, officefromMay 2014 to December2017. He also previouslyservedasManager, DivisionExplorationin EOG'sFortWorth, Texas, andMidland,Texas,offices from March 2012 to May2014 as wellasinvarious geoscienceand leadershippositions. Mr. Yacob joined EOG in August 2005.

Kenneth W. Boedekerwas electedExecutive Vice President, Exploration and Production in December2018. He served as VicePresident and General ManagerofEOG's Denver, Colorado, office from October 2016 to December2018, and as VicePresident,Engineering and Acquisitions from July2015 to October 2016. Prior to that, Mr. Boedeker heldtechnical and managerialpositions of increasing responsibilityacrossmultipleoffices andfunctional areaswithin EOG. Mr.Boedeker joinedEOG in July1994.

Timothy K. Driggers waselected Executive VicePresident andChief Financial OfficerinApril 2016. Previously, Mr. Driggers servedasVicePresident andChief FinancialOfficer from July 2007 to April 2016. He was elected Vice President and Controller of EOG in October 1999, wassubsequentlynamed Vice President,Accounting and Land Administration in October 2000 and VicePresident andChiefAccounting OfficerinAugust 2003. Mr. Driggers is EOG's principal financial officer. Mr. Driggers joinedapredecessor of EOGinAugust1995.

Michael P. Donaldson waselected Executive Vice President,GeneralCounseland Corporate Secretary in April 2016. Previously, Mr. Donaldson servedasVice President,General Counseland CorporateSecretaryfromMay 2012 to April 2016. He waselectedCorporate Secretary in May 2008, and was appointedDeputyGeneral Counsel and Corporate SecretaryinJuly 2010. Mr. Donaldson joined EOG in September2007.

ITEM1A. Risk Factors

Our business andoperations aresubject to many risks. Therisks described belowmay notbethe only risks we face, as ourbusiness and operations may also be subjecttorisks thatwedonot yet know of, or thatwecurrentlybelieveare immaterial. If any of the events or circumstances described below actually occurs, our business, financial condition, results of operations or cash flows couldbemateriallyand adversely affected and the trading price of ourcommon stockcould decline. The following risk factorsshould be readinconjunction withthe other information containedherein, includingthe consolidated financial statements and the related notes. Unless the context requires otherwise,“we,” “us,” “our” and “EOG”refertoEOG Resources, Inc.and itssubsidiaries.

RisksRelatedtoour Financial Condition, Results of Operations and Cash Flows

Crude oil, natural gas and NGL pricesare volatile, andasubstantial andextendeddecline in commoditypricescan have a material and adverseeffect on us.

Prices for crude oiland natural gas (including prices fornatural gasliquids (NGLs)and condensate)fluctuatewidely. Among the interrelated factorsthatcan or could causethese price fluctuations are:

• domesticand worldwide supplies of crude oil, NGLs andnaturalgas; • domesticand internationaldrilling activity;

13 • theactions of othercrude oilproducing and exporting nations, including the Organization of Petroleum Exporting Countries; • consumer andindustrial/commercial demand for crude oil,naturalgas and NGLs; • worldwide economic conditions, geopoliticalfactors and politicalconditions, including, but not limited to,the imposition of tariffsortrade or othereconomic sanctions,politicalinstability or armed conflict in oiland gas producing regions; • theduration and economic and financial impact of epidemics,pandemics or otherpublichealthissues, such as the ongoing COVID-19 pandemic; • the availability, proximityand capacityofappropriate transportation, gathering, processing, compression, storage and refining facilities; • theprice andavailabilityof, and demand for, competing energy sources, including alternativeenergy sources; • the effect of worldwide energy conservation measures, alternative fuel requirementsand climate change-related initiatives; • thenature andextent of governmentalregulation,including anychanges or otheractionswhichmay resultfromthe recentelections in theUnited StatesofAmerica (UnitedStates or U.S.)and change in administration,and including environmental andother climatechange-relatedregulation, regulation of derivativestransactions and hedging activities,tax lawsand regulations and laws and regulations withrespect to theimport and exportofcrude oil,NGLs, and naturalgas andrelated commodities; • the level and effectoftrading in commodity futures markets, includingtrading by commodityprice speculators and others; and • weatherconditions and changesinweather patterns.

In thefirst half of 2020,the pricesfor crude oil,NGLs and natural gasdeclinedsubstantially as aresult of the economic downturn and overall reduction of demand prompted by the COVID-19pandemic andthe oversupplyofcrude oil from certainforeign oil-exporting countries. In the second halfof2020, (i) the prices for NGLs andnatural gasrecoveredto pre-pandemic levels and (ii) thepricesfor crude oil increased butremain significantly below pre-pandemic levels.

The above-described factors and the volatility of commoditypricesmakeitdifficult to predict crude oil, NGLs and natural gas prices in 2021 andthereafter. As aresult, there canbenoassurance that thepricesfor crude oil, NGLs and/or natural gaswill continue to increase from,orsustain, theircurrent levels, nor canthere be any assurance that the pricesfor crude oil,NGLsand/or naturalgas will not again decline.

Ourcashflows andresults of operations depend to agreat extent on prevailingcommodity prices.Accordingly, substantial andextendeddeclinesincommodity pricescan materially and adverselyaffect the amount of cash flows we have availablefor our capital expenditures and operatingexpenses,the termsonwhich we canaccess the credit and capital markets and our results of operations.

Lowercommodity pricescan also reducethe amount of crude oil, NGLs and naturalgas thatwecan produce economically.Substantial and extendeddeclinesinthe prices of these commodities canrender uneconomicaportionofour exploration, developmentand exploitation projects, resulting in ourhaving to make downward adjustmentstoour estimated proved reservesand also possibly shut in or plug and abandon certainwells. In addition,significant prolonged decreases in commodity prices maycause theexpected future cash flowsfromour properties to fall below their respectivenet book values, whichwould require us to writedown the value of ourproperties. Suchreserve write-downs and asset impairments can materially and adversely affectour resultsofoperations andfinancial position and, in turn,the trading price of ourcommon stock.

In fact,the substantial declines in crude oil, NGLsand naturalgas pricesthatoccurred in thefirsthalfof2020 materiallyand adversely affected the amount of cash flows we hadavailablefor our 2020 capital expenditures and operating expenses, our results of operations during the first half of 2020 and the trading price of ourcommonstock.Such commodity price declines also resulted in aggregateimpairmentcharges of approximately$1.8billioninthe first half of 2020 withrespect to our provedoil and gaspropertiesand related assets. Such declinesincommodity pricesalsoresulted in ourmakinga downward adjustment of 278 million barrelsofoil equivalent to our estimatednet proved reservesatDecember 31, 2020.

14 If commoditypricesdecline from current levels for an extendedperiodoftime, ourfinancialcondition, cash flows and results of operations willbeadversely affected and we maybelimited in our abilitytomaintain ourcurrent level of dividends on our common stock. In addition, we mayberequired to incur additional impairment chargesand/or make additional downward adjustments to our proved reserve estimates. As aresult, our financial condition and results of operations andthe trading price of our commonstockmay be materiallyand adversely affected.

We havesubstantial capital requirements, and we may be unable to obtain neededfinancing on satisfactory terms,ifatall.

We make, andwillcontinuetomake, substantialcapital expenditures forthe acquisition,exploration, development, production andtransportation of crude oil,NGLs andnatural gas reserves.Weintend to financeour capitalexpenditures primarily throughour cash flows from operations andsales of non-core assetsand, to alesserextent andifand as necessary, commercial paper borrowings, bank borrowings,borrowings under our revolving credit facility and public and private equity and debt offerings.

Lowercrude oil,NGLs and naturalgas prices,however, reduceour cash flows and couldalsodelay or impairour ability to consummate certain planned non-core asset sales anddivestitures. Further, if thecondition of the credit andcapital marketsmaterially declines, we might not be abletoobtainfinancingonterms we consideracceptable, if at all. In addition, weakness and/or volatility in domesticand globalfinancialmarkets or economic conditions or adepressedcommodity price environment mayincrease the interestrates that lenders andcommercial paperinvestors require us to payoradversely affect our ability to financeour capital expenditures through equity or debt offerings or otherborrowings.

Similarly, areduction in our cash flows (for example, as aresultoflower crudeoil,natural gas and/or NGLs pricesor unanticipated wellshut-ins) and the corresponding adverse effect on our financial conditionand results of operations mayalso increase the interest rates thatlenders and commercial paper investors require us to pay. Asubstantial increase in interest rates would decrease our net cash flows availablefor reinvestment. Any of these factors could haveamaterial andadverseeffect on our business, financial condition and results of operations.

Further, our ability to obtainfinancings, our borrowing costsand the terms of anyfinancings are, in part,dependent on the creditratings assigned to ourdebt by independent credit ratingagencies. Theinterrelated factors thatmay impactour credit ratings includeour debt levels; planned capital expendituresand sales of assets; near-termand long-term production growth opportunities;liquidity; asset quality; cost structure; productmix; and commodity pricing levels (including, but not limited to, the estimatesand assumptions of credit ratingagencies withrespect to future commodityprices). We cannot provideany assurancethatour current creditratings will remainineffect for any given period of timeorthat our credit ratingswillberaised in thefuture,nor can we provideany assurancethat any of our creditratings will notbelowered.

Reserveestimates depend on many interpretationsand assumptions. Any significant inaccuracies in these interpretations and assumptions could cause the reported quantities of our reserves to be materially misstated.

Estimating quantitiesofcrude oil,NGLs and natural gas reservesand future net cash flows from such reserves is a complex,inexactprocess.Itrequires interpretations of available technical dataand various assumptions, includingassumptions relatingtoeconomic factors, made by our management. Any significant inaccuraciesinthese interpretations or assumptions could cause the reported quantities of our reservesand future net cash flowsfrom suchreserves to be overstatedorunderstated. Also, the data for agivenreservoir mayalsochange substantially over timeasaresultofnumerousfactorsincluding, but not limited to, additional developmentactivity, evolving production history, continual reassessmentofthe viability of production under varying economic conditionsand improvementsand otherchanges in geological, geophysicaland engineering evaluation methods.

15 To prepareestimates of our economically recoverablecrude oil, NGLs andnatural gasreservesand future net cash flows from ourreserves, we analyzemanyvariablefactors,suchashistoricalproduction from the area comparedwith production rates from other producing areas. We also analyze available geological, geophysical, production and engineering data, and the extent, qualityand reliabilityofthis datacan vary. Theprocess also involves economic assumptions relating to commodity prices, production costs,gathering, processing, compression, storage andtransportation costs, severance, ad valoremand otherapplicabletaxes, capital expenditures andworkover andremedial costs.Manyofthese factors are or maybe beyond ourcontrol.Our actualreserves and future net cash flows from such reservesmost likely will vary from our estimates. Any significant variance,including any significant downward revisions to ourexisting reserve estimates, couldmaterially and adversely affect our business, financial condition and results of operations and, in turn, the trading price of our common stock. For related discussion, see ITEM 2, Properties -Oil andGas Exploration and Production -Properties andReservesand Supplemental InformationtoConsolidatedFinancialStatements.

If we failtoacquire or findsufficientadditional reserves over time,our reservesand production will decline from their current levels.

The rateofproduction from crude oiland naturalgas properties generally declines as reserves are produced. Exceptto the extentthatweconductsuccessful exploration, exploitation and development activities resulting in additional reserves, acquire additional properties containing reserves or, through engineering studies,identify additionalbehind-pipe zonesor secondary recovery reserves, our reserves willdeclineastheyare produced. Maintaining our production of crude oiland natural gasat, or increasingour production from, current levels, is, therefore, highly dependent upon our level of success in acquiring or finding additional reserves,whichmay be adverselyimpacted by bans or restrictions on drilling. To the extent we areunsuccessful in acquiring or finding additional reserves,our future cash flows and results of operations and, in turn,the trading price of our commonstockcould be materiallyand adversely affected.

Our hedging activities may prevent us from fully benefitingfrom increasesincrude oil, NGLs and natural gaspricesand may expose us to otherrisks, including counterparty risk.

We use derivativeinstruments (primarilyfinancial basisswap, priceswap, option, swaption and collarcontracts) to hedgethe impactoffluctuations in crude oil, NGLs andnatural gas prices on our resultsofoperations andcashflows.Tothe extent thatweengage in hedgingactivities to protect ourselvesagainstcommodity price declines, we maybeprevented from fullyrealizing the benefits of increasesincrude oil, NGLs and natural gasprices above the prices established by our hedging contracts. Aportion of our forecastedproduction for2021and 2022 is subject to fluctuatingmarket prices.Ifweare ultimately unabletohedgeadditional productionvolumes for 2021, 2022 andbeyond,wemay be materiallyand adversely impactedby any declinesincommodity prices, which mayresultinlower netcashprovidedbyoperating activities. In addition,our hedging activities mayexpose us to theriskoffinancialloss in certain circumstances,including instances in whichthe counterpartiesto our hedging contracts fail to performunderthe contracts.

The inability of our customers and othercontractual counterpartiestosatisfy their obligations to us may have amaterial and adverse effect on us.

We have various customers for the crudeoil,naturalgas and related commodities that we produceaswell as various other contractual counterparties, includingseveral financial institutions and affiliatesoffinancial institutions. Domestic and globaleconomicconditions, including the financial condition of financial institutionsgenerally, mayadversely affectthe ability of our customers and other contractualcounterparties to pay amounts owed to us from time to timeand to otherwisesatisfy their contractual obligationstous, as well as their ability to access the credit and capitalmarkets for suchpurposes.

Moreover, our customers and other contractualcounterparties maybeunabletosatisfy their contractualobligations to us forreasons unrelatedtothese conditions andfactors, such as the unavailabilityofrequired facilities or equipment due to mechanical failure or market conditions. Furthermore, if acustomer is unabletosatisfyits contractualobligation to purchase crude oil, naturalgas or related commodities from us, we maybeunable to sell such production to anothercustomer on terms we consider acceptable,ifatall, due to the geographic locationofsuchproduction; theavailability, proximity and capacity of appropriate gathering, processing, compression, storage,transportation andrefining facilities; or market or otherfactors and conditions.

16 Theinability of our customers and othercontractualcounterparties to payamounts owedtousand to otherwise satisfy their contractual obligations to us may materially and adversely affect our business, financial condition,resultsofoperations and cash flows.

Risks Related to our Operations

Drilling crude oiland natural gas wells is ahigh-risk activity andsubjectsustoavarietyofrisksthatwecannotcontrol.

Drilling crude oiland natural gas wells, including development wells, involvesnumerous risks, including the risk that we maynot encounter commercially productive crude oil, NGLsand/ornatural gasreserves. As aresult, we may not recover allorany portion of our investment in newwells.

Specifically,weoftenare uncertainastothe future cost or timingofdrilling, completing and operating wells, and our drilling operations and those of ourthird-partyoperators maybecurtailed, delayed or canceled, the cost of suchoperations may increase and/or our results of operations andcash flows from such operations may be impacted,asaresult of avariety of factors,including:

• unexpected drillingconditions; • titleproblems; • pressure or irregularitiesinformations; • equipment failures or accidents; • adverse weatherconditions, suchaswinter storms, flooding, tropical storms and hurricanes, and changes in weather patterns; • compliancewith, or changes in (including theadoption of new), environmental,health and safety laws and regulations relatingtoair emissions, hydraulicfracturing, access to and use of water,disposal or otherdischarge (e.g., into injectionwells) of producedwater,drilling fluids and otherwastes, laws andregulations imposing conditions or restrictions on drilling and completion operations and on the transportation of crude oiland natural gas, and other laws and regulations, suchastax laws and regulations; • theavailability andtimelyissuanceofrequired federal,state,tribaland other permitsand licenses, whichmay be adversely affected by (among otherthings) bans or restrictions on drilling, government shutdowns or othersuspensions of, or delays in, government services; • the availability of,costsassociated withand terms of contractualarrangements for properties, including mineral licenses and leases, pipelines, crude oil hauling trucks and qualified drivers and facilities and equipment to gather, process, compress, store, transport, marketand export crudeoil, naturalgas andrelated commodities; and • thecosts of, or shortages or delaysinthe availabilityof, drilling rigs, hydraulic fracturingservices, pressure pumping equipment andsupplies,tubularmaterials, water, sand, disposalfacilities, qualified personnel and othernecessary facilities, equipment, materials, suppliesand services.

Our failure to recover our investment in wells, increases in the costsofour drilling operations or those of ourthird- party operators, and/or curtailments, delays or cancellations of our drilling operations or those of our third-party operators,in each case, due to any of the above factors or other factors, maymateriallyand adversely affectour business, financialcondition and results of operations.For related discussion of the risks andpotentiallosses and liabilitiesinherent in ourcrude oil and natural gas operationsgenerally, see the immediatelyfollowing risk factor.

Our crude oil, NGLs and natural gas operations and supporting activities and operations involve many risks and expose us to potential losses andliabilities, and insurancemay not fully protectusagainst these risks and potential losses and liabilities.

Our crude oil, NGLsand naturalgas operations and supporting activities and operations aresubject to allofthe risks associated with exploring anddrilling for, andproducing,gathering,processing, compressing, storing andtransporting, crude oil and natural gas, includingthe risks of:

• wellblowouts andcratering; • loss of well control; • crude oil spills, natural gas leaks,formation water (i.e.,produced water) spillsand pipeline ruptures;

17 • pipe failuresand casing collapses; • uncontrollable flows of crude oil, natural gas, formation water or drillingfluids; • releasesofchemicals,wastesorpollutants; • adverse weather events, suchaswinter storms, flooding, tropicalstormsand hurricanes, andother natural disasters; • fires and explosions; • terrorism,vandalismand physical, electronic andcybersecuritybreaches; • formations with abnormalorunexpected pressures; • leaksorspills in connection with, or associatedwith, thegathering, processing, compression, storage and transportation of crude oil, NGLs andnaturalgas;and • malfunctions of, or damage to, gathering, processing, compression andtransportation facilitiesand equipment and otherfacilitiesand equipment utilized in supportofour crude oil and natural gas operations.

If any of theseeventsoccur, we could incurlosses, liabilities and other additional costs as aresultof:

• injury or loss of life; • damage to,ordestruction of, property, facilities, equipment and crudeoil and natural gas reservoirs; • pollution or otherenvironmental damage; • regulatory investigations andpenalties as well as cleanupand remediation responsibilitiesand costs; • suspension or interruption of our operations, includingdue to injunction; • repairsnecessary to resumeoperations;and • compliance with laws and regulations enacted as aresultofsuchevents.

We maintaininsurance against many, but not all, such losses and liabilities in accordance with what we believe are customary industry practices andinamounts and at coststhat we believe to be prudentand commercially practicable. However, the occurrence of any of these eventsand anylossesorliabilitiesincurredasaresultofsuchevents, if uninsured or in excess of our insurancecoverage,would reducethe funds available to us forour operations and could, in turn,have amaterial andadverseeffectonour business, financial condition andresults of operations.

Our ability to sell anddeliver our crude oil, NGLs and natural gasproduction could be materially andadverselyaffectedif adequategathering, processing, compression, storage,transportation and export facilitiesand equipmentare unavailable.

The saleofour crude oil,NGLs and natural gas production depends on anumberoffactors beyond our control, including the availability, proximity and capacityof, andcostsassociated with, gathering, processing, compression, storage, transportation and export facilities andequipment owned by third parties. These facilities and equipment maybetemporarily unavailabletousdue to market conditions, regulatory reasons, mechanical reasonsorother factors or conditions, and maynot be availabletousinthe future on termsweconsideracceptable,ifatall. In particular,incertain newerplays, the capacity of gathering, processing, compression, storage,transportation andexport facilities and equipment maynot be sufficientto accommodate potential production from existing andnew wells.Inaddition,lackoffinancing, construction andpermitting delays, permitting costsand regulatory or other constraintscouldlimit or delay theconstruction, manufacture or other acquisition of newgathering, processing, compression, storage, transportation and export facilities andequipment by third parties or us, andwemay experiencedelays or increased costsinaccessing the pipelines,gatheringsystems or rail systems necessary to transport ourproduction to pointsofsaleordelivery.

Anysignificant change in market or otherconditions affecting gathering, processing, compression, storage, transportation and export facilities andequipment or the availabilityofthese facilities andequipment,including due to our failure or inabilitytoobtain access to these facilities and equipmentonterms acceptable to us or at all,could materially and adversely affect our business and, in turn,our financial condition and results of operations.

18 Aportionofour crude oil, NGLsand natural gasproduction may be subject to interruptions that could have amaterial and adverse effect on us.

Aportion of our crude oil, NGLs andnatural gasproduction maybeinterrupted, or shut in, from time to timefor various reasons, including, but not limited to, as aresultofaccidents, weatherconditions, the unavailability of gathering, processing, compression, storage,transportation,refining or export facilities or equipment or field laborissues, or intentionally as aresult of marketconditions such as crude oil, NGLs or natural gas pricesthat we deem uneconomic.Ifasubstantial amount of our production is interrupted or shut in,our cash flows and, in turn, our financialconditionand results of operations couldbematerially andadversely affected.

We havelimited control over the activities on properties that we do notoperate.

Some of the propertiesinwhich we have an interestare operatedbyother companiesand involve third-party working interest owners. As aresult, we have limited ability to influenceorcontrol the operationorfuturedevelopment of such properties,including compliance with environmental,safety and other regulations, or the amount of capital expendituresthatwe willberequiredtofund withrespecttosuch properties. Moreover, we are dependent on the otherworking interest owners of such projectstofund their contractualshare of the capital expenditures of such projects. In addition, athird-party operator couldalso decide to shut-in or curtail production from wells, or plug and abandon marginal wells, on properties owned by that operator during periods of lower crude oil, NGLsornaturalgas prices.These limitationsand our dependence on the operator and third-partyworking interest owners for these projectscould cause us to incur unexpected future costs, lower production and materiallyand adversely affect our financialconditionand results of operations.

If we acquirecrude oil, NGLs andnatural gas properties, our failuretofullyidentify existing and potential problems, to accuratelyestimate reserves,production ratesorcosts, or to effectivelyintegratethe acquired properties into ouroperations couldmaterially and adverselyaffect ourbusiness,financial condition andresultsofoperations.

From time to time,weseek to acquire crudeoil and natural gasproperties -for example,our October 2016 mergers and related assetpurchase transactions withYatesPetroleum Corporation and certain of its affiliated entities.Although we perform reviewsofpropertiestobeacquired in amannerthatwebelieveisduly diligent andconsistent with industrypractices, reviews of records and properties maynot necessarilyreveal existing or potential problems (such as titleorenvironmental issues), nor maytheypermit us to becomesufficiently familiar withthe properties in order to fullyassess their deficiencies and potential. Even when problemswith aproperty are identified, we oftenmay assume environmentaland otherrisks and liabilities in connection withacquiredpropertiespursuanttothe acquisition agreements.

In addition,there arenumerous uncertainties inherent in estimating quantities of crudeoil andnatural gas reserves (as discussed further above), actual future production rates and associatedcostswithrespect to acquiredproperties. Actual reserves,productionrates and costsmay vary substantially from those assumed in ourestimates. In addition, an acquisition mayhaveamaterial and adverseeffect on our business and results of operations, particularlyduringthe periods in which the operations of the acquired properties arebeing integratedinto our ongoing operations or if we areunabletoeffectively integrate the acquiredpropertiesintoour ongoing operations.

Competition in the oiland gas exploration and production industry is intense, andsomeofour competitors have greater resourcesthan we have.

We compete with major integrated oil and gas companies, government-affiliatedoil andgas companiesand other independent oiland gas companies forthe acquisitionoflicenses and leases, properties and reserves and access to the facilities, equipment,materials, servicesand employeesand other personnel(including geologists, geophysicists, engineers andother specialists)necessary to explore for,develop, produce,marketand transport crude oil,NGLsand natural gas. Certainofour competitors have financial and other resourcessubstantiallygreater thanthose we possess and have established strategiclong- term positionsorstrong governmental relationships in countries or areas in which we may seek new or expanded entry. As a consequence, we may be at acompetitivedisadvantageincertain respects, such as in bidding for drilling rightsorinaccessing necessary services, facilities, equipment,materialsand personnel.Inaddition, our larger competitors mayhave acompetitive advantage when responding to factors thataffect demandfor crude oil, NGLsand naturalgas, such as changing worldwide prices and levels of production and the cost andavailability of alternative fuels.Wealso face competition from competing energy sources, such as renewable energy sources.

19 Risks Related to OurInternational Operations

We operate in other countries and, as aresult,are subject to certainpolitical, economicand other risks.

Our operations in jurisdictions outside the U.S. are subjecttovariousrisksinherent in foreign operations. These risks include,among other risks:

• increases in taxes and governmentalroyalties; • changes in lawsand policies governing operations of foreign-based companies; • loss of revenue, loss of or damage to equipment, property and other assetsand interruption of operations as aresult of expropriation,nationalization,actsofterrorism, war, civilunrest andother political risks; • unilateralorforcedrenegotiation,modification or nullification of existing contractswithgovernmental entities; • difficultiesenforcingour rightsagainst agovernmentalagency because of the doctrine of sovereign immunity and foreign sovereignty overinternational operations; and • currency restrictionsorexchange ratefluctuations.

Our international operations mayalso be adverselyaffected by U.S. laws and policies affecting foreign trade and taxation, includingtariffs or trade or othereconomic sanctions;modifications to, or withdrawalfrom, international trade treaties;and U.S. laws withrespecttoparticipationinboycotts thatare notsupportedbythe U.S. government. The realization of anyofthese factors could materially andadversely affect our business,financial condition and resultsofoperations.

Unfavorable currencyexchange ratefluctuations couldmaterially and adversely affectour resultsofoperations.

The reporting currency for our financialstatementsisthe U.S. dollar. However, certain of our subsidiaries arelocated in countriesother thanthe U.S. and have functionalcurrencies otherthan the U.S. dollar. Theassets, liabilities, revenuesand expensesofcertain of these foreign subsidiariesare denominated in currencies other thanthe U.S. dollar. To prepare our consolidatedfinancial statements, we musttranslate thoseassets, liabilities, revenues and expenses intoU.S. dollars at then- applicable exchange rates. Consequently, increases and decreases in the valueofthe U.S. dollarversus other currencies will affect the amount of these items in ourconsolidatedfinancial statements, evenifthe amount hasnot changedinthe original currency. Thesetranslations couldresultinchanges to our results of operations from periodtoperiod. For the fiscalyear endedDecember 31,2020, less than1%ofour net operatingrevenuesrelatedtooperations of our foreign subsidiarieswhose functionalcurrency wasnot the U.S.dollar.

RisksRelated to Regulatoryand Legal Matters

The regulatory,legislative andpolicychangespursuedbythe newU.S.presidential administration may materiallyand adversely affect the oil and gas exploration and production industry.

In November 2020, Joseph R. Biden Jr. was electedPresident of the United States.New or revised rules, regulations and policiesmay be issued, and new legislation maybeproposed, during the current administration thatcouldimpactthe oil and gas exploration and production industry.Suchrules,regulations,policies and legislation may affect,among otherthings, (i) permitting for oil and gas drilling on federal lands,(ii)the leasingoffederal lands for oil and gasdevelopment, (iii) the regulationofgreenhousegas (GHG)emissionsand/or otherclimate change-relatedmatters associated withoil andgas operations, (iv) the use of hydraulic fracturing on federal lands, (v)the calculationofroyalty paymentsinrespect of oil andgas production from federal landsand (vi)U.S.federal income taxlaws applicable to oiland gas explorationand production companies. On January 27, 2021, President Bidenissued Executive Order14008 entitled “Tackling the ClimateCrisis at Home and Abroad,”directingthe Secretary of the Interior, to the extent consistent with applicable law andinconsultationwithother agencies andstakeholders, to (i)pause approval of new oil and naturalgas leasesonfederal lands or in offshore waterspending completionofacomprehensive reviewand reconsideration of federal oiland gas permitting and leasing practices and (ii) considerwhethertoadjust royaltiesassociated withoil andgas resources extracted from federal lands and offshore waters to account for corresponding climate costs.

20 Further, suchregulatory, legislativeand policy changes may, among otherthings,result in additional permittingand disclosure requirements, additionaloperating restrictions and/or the imposition of various conditions and restrictions on drilling and completion operations or otheraspectsofour business, any of whichcouldlead to operationaldelays,increased operating and compliancecosts and/or otherimpacts on ourbusinessand operations and could materially and adversely affect our business, resultsofoperationsand financial condition.

For related discussion,see the belowriskfactors regarding legislativeand regulatory matters impacting the oiland gas exploration and production industry.

We incur certaincoststocomplywithgovernment regulations,particularly regulationsrelating to environmental protection and safety,and couldincur even greatercostsinthe future.

Our crude oil, NGLs and naturalgas operations and supporting activities are regulated extensivelybyfederal,state, tribal and local governments and regulatory agencies, both domestically and in the foreign countriesinwhich we do business, and aresubject to interruption or termination by governmentaland regulatory authorities basedonenvironmental,health, safety or other considerations. Moreover, we have incurredand will continue to incur costs in ourefforts to comply withthe requirementsofenvironmental,health, safety andother regulations. Further, theregulatory environment couldchangeinways that we cannot predict andthatmightsubstantially increase our costsofcomplianceand/or adverselyaffect our business and operations and, in turn, materiallyand adverselyaffect our results of operations and financial condition, includingany changes thatmay result from the recentU.S. elections and changeinadministration (seethe risk factorabove withrespecttothe new U.S. administration).

Specifically,asacurrent or past ownerorlessee andoperator of crude oiland naturalgas properties, we aresubjectto various federal,state, tribal,local andforeign regulations relating to the discharge of materials into, and the protection of, the environment.Theseregulations may, among other things, impose liabilityonusfor the cost of pollution cleanup resulting from current or past operations, subjectustoliability forpollution damages and requiresuspension or cessation of operations in affected areas. Changesin, or additions to, these regulations, including any changes thatmay resultfromthe recentU.S. elections and change in administration, couldleadtoincreased operating andcompliance costs and, in turn, materiallyand adversely affect our business, resultsofoperationsand financial condition.

The regulation of hydraulic fracturing is primarily conducted at the stateand local levelthrough permittingand other compliancerequirementsand, further, somestate and local governmentshave imposedorhave considered imposing various conditions and restrictions on drilling and completionoperations. TheU.S. Environmental Protection Agency(U.S. EPA) has issuedregulationsrelatingtohydraulicfracturing and there havebeen various otherproposalstoregulate hydraulic fracturingat the federal level. In addition,there were proposals and positions taken by President Biden during his campaignregarding the use of hydraulic fracturing on federal landsand waters. Further, on January 27, 2021, President Biden issuedExecutiveOrder 14008 entitled "Tackling the ClimateCrisis at Home andAbroad," directing the Secretaryofthe Interior, to theextent consistent with applicablelaw and in consultation withother agencies and stakeholders, to, among other things, pause approval of new oil andnatural gas leases on federal lands or in offshore waters pendingcompletion of acomprehensive reviewand reconsideration of federal oil and gaspermitting andleasing practices.

Any such requirements, restrictions, conditions or prohibition couldleadtooperationaldelaysand increased operating and compliancecostsand, further, could delay or effectively prevent the developmentofcrude oiland natural gasfrom formations whichwould not be economically viablewithout the use of hydraulic fracturing.Accordingly, our production of crude oiland naturalgas couldbematerially and adversely affected.For additional discussion regarding hydraulic fracturing regulation, seeRegulation of Hydraulic Fracturing and Other Operations -UnitedStates under ITEM 1, Business -Regulation.

We will continue to monitor and assess any proposed or newpolicies, legislation, regulations and treaties in the areas where we operate to determinethe impact on ouroperations and take appropriateactions,where necessary. We are unableto predict the timing,scope andeffect of any currentlyproposed or future laws, regulationsortreaties, but the directand indirect costsofsuchlaws, regulations and treaties (if enacted) couldmaterially and adversely affect our business, results of operations and financial condition. See also the risk factor below regarding the provisions of the Dodd-FrankWallStreet Reformand Consumer Protection Act withrespect to regulation of derivatives transactions and entities(such as EOG) thatparticipate in such transactions.

21 Regulations,government policiesand government and corporate initiatives relating to greenhouse gasemissions and climate change could haveasignificant impact on our operations and we could incursignificant cost in thefuturetocomply.

Local,state, federal andinternational regulatorybodieshavebeen increasingly focused on GHG emissions and climate change issuesinrecent years. For example,weare subjecttothe U.S. EPA’s rule requiring annualreporting of GHG emissions.Inaddition, our oil andgas production and processing operations aresubject to theU.S. EPA's new source performancestandards applicabletoemissions of volatile organiccompounds from new, modifiedand reconstructedcrude oil and naturalgas wellsand equipment locatedatnatural gasproduction gathering andboosterstations and gasprocessing plants.

At the internationallevel, in December2015, the U.S. participated in the 21st Conference of the Parties of theUnited Nations Framework Convention on ClimateChangeinParis, France.The Paris Agreement (adopted at the conference) calls for nations to undertake efforts withrespect to globaltemperatures and GHG emissions. The Paris Agreement wentintoeffect on November 4, 2016. Whilethe U.S. withdrew from the Paris AgreementonNovember 4, 2020, President Biden issuedan executive orderonJanuary 20, 2021 recommittingthe United States to the Paris Agreement. In addition, many stateand local officials have stated theirintent to intensify effortstouphold the commitmentsset forth in the internationalaccord. Further, on January 27, 2021, President Bidenissued Executive Order14008 entitled 'Tackling the ClimateCrisis at Home andAbroad,' directing the Secretaryofthe Interior, to theextent consistent with applicable lawand in consultation with otheragenciesand stakeholders,to, among otherthings,consider whethertoadjust royaltiesassociated with oil andgas resourcesextracted from federal lands and offshore waters to account for corresponding climatecosts.

It is possible that theParis Agreement and subsequent domesticand international regulationsand government policies willhave adverse effectsonthe market for crude oil,natural gasand otherfossilfuelproductsaswellasadverse effectsonthe business and operations of companies engagedinthe exploration for, and production of, crude oil, natural gasand other fossil fuel products.Weare unabletopredict the timing,scope andeffect of any currently proposedorfutureinvestigations,laws, regulations, treatiesorpolicies regarding climatechange andGHG emissions (includingany lawsand regulations thatmay be enacted in the U.S. by the new administration),but the directand indirect costs of such developments(if enacted, issuedor applied)could materiallyand adversely affectour operations, financialconditionand results of operations. Further, the increasing attention to global climatechange risks has createdthe potential for agreater likelihoodofgovernmental investigations and private andpublic litigation, which couldincrease our costsorotherwise adversely affect ourbusiness. For additional discussion regarding climate change regulation,see (i) ClimateChange -United States under ITEM1,Business – Regulation and (ii) the risk factor above with respecttothe new U.S. administration.

In addition, the achievement of our current or future internal initiatives relatingtothe reductionofGHG emissions mayincreaseour costs, including requiring us to purchase emissions creditsoroffsets, or mayimpact or otherwise limitour ability to executeonour business plans.

Further, increasing attention to globalclimate changerisks hascreated the potential for agreater likelihood of governmental investigationsand private andpublic litigation, whichcould increase our costs or otherwise adverselyaffect our business.

Tax lawsand regulations applicabletocrude oiland natural gasexploration and production companies may change over time, and such changescould materially and adversely affectour cash flows, resultsofoperations and financial condition.

From time to time,legislation has beenproposedthat,ifenactedintolaw, would make significant changes to U.S. federal incometax laws applicable to crudeoil andnatural gasexploration and production companies, such as withrespect to theintangible drilling and development costsdeduction andbonus tax depreciation. While these specific changeswerenot includedinthe Tax Cutsand Jobs Actsignedinto lawinDecember 2017,noaccurate prediction canbemadeastowhether any such legislative changesorsimilar or other taxlaw changes willbeproposedinthe future (for example,bythe newU.S. administration)and, if enacted, whatthe specific provisions or the effective dateofany suchlegislation would be.The elimination of certain U.S. federal incometax deductions, as well as anyotherchanges to, or the imposition of new, federal, state, local or non-U.S. taxes(including the imposition of, or increases in, production, severance or similar taxes), could materiallyand adversely affect our cash flows, results of operations and financialcondition.

In addition, legislation may be proposed withrespect to theenactment of atax levied on the carboncontent of fuels basedonthe GHGemissions associated with suchfuels. Acarbontax would generallyincrease the prices for crude oil, natural gasand NGLs.Suchprice increases may, in turn, reducedemand for crude oil,naturalgas and NGLs and materiallyand adversely affect our cash flows, results of operations and financialcondition.

22 We areunabletopredictthe timing, scopeand effect of any proposedorenacted tax law changes, but anysuch changes (if enacted) couldmaterially andadverselyaffect our business, results of operations andfinancialcondition.Wewill continue to monitor and assess any proposed or enacted taxlaw changes to determine the impact on ourbusiness, results of operations and financial condition and takeappropriateactions,where necessary.

Federal legislationand relatedregulations regarding derivatives transactions could haveamaterial and adverse impactonour hedgingactivities.

As discussedinthe risk factor above regarding our hedging activities,weuse derivativeinstrumentstohedge the impact of fluctuations in crude oil,NGLsand natural gas prices on our results of operations and cash flows. In 2010, Congress adopted the Dodd-Frank Wall Street Reform and ConsumerProtection Act(Dodd-Frank Act), which, among othermatters, providesfor federal oversight of the over-the-counterderivativesmarketand entities that participate in that market and mandates thatthe CommodityFuturesTrading Commission (CFTC), the U.S. Securitiesand Exchange Commission (SEC) and certain federalagenciesthatregulate the bankingand insurance sectors (the PrudentialRegulators) adopt rulesorregulations implementing the Dodd-FrankAct andproviding definitions of terms used in the Dodd-Frank Act. TheDodd-FrankAct establishes marginrequirements and requires clearing and trade execution practices for certain categoriesofswaps and may resultincertain market participants needing to curtail their derivatives activities.Although some of the rulesnecessary to implement the Dodd-Frank Act areyet to be adopted, the CFTC,the SEC andthe Prudential Regulators have issuednumerous rules, including arule establishing an “end-user” exception to mandatory clearing (End-UserException), arule regarding margin for unclearedswaps (MarginRule) andaproposedrule imposing position limits (Position Limits Rule).

We qualifyasa"non-financial entity" for purposes of the End-UserException and, as such, we areeligible for such exception. As aresult, our hedging activities are not subject to mandatory clearing or the margin requirementsimposedin connection with mandatory clearing. We also qualifyasa"non-financial enduser" for purposes of the MarginRule;therefore, our uncleared swaps arenot subjecttoregulatory marginrequirements. Finally, we believeour hedging activitieswould constitute bona fidehedging under the Position Limits Ruleand would not be subject to limitation undersuchrule if it is enacted.However, many of our hedge counterpartiesand many othermarketparticipantsare not eligible forthe End-User Exception, are subject to mandatory clearing and the Margin Rulefor swaps withsomeorall of their otherswapcounterparties, and maybesubjecttothe Position Limits Rule. In addition, the European Union and other non-U.S. jurisdictionshave enacted laws and regulationsrelated to derivatives(collectively, Foreign Regulations) whichapplytoour transactionswith counterparties subjecttosuchForeign Regulations.

TheDodd-Frank Act, the rulesadopted thereunderand the Foreign Regulationscould increasethe cost of derivative contracts, alter the terms of derivativecontracts, reducethe availability of derivatives to protect againstthe pricerisks we encounter, reduceour ability to monetize or restructure our existing derivative contracts, lessen the numberofavailable counterparties and, in turn, increase our exposure to less creditworthy counterparties. If our use of derivativesisreduced as a resultofthe Dodd-Frank Act, related regulations or the Foreign Regulations, our results of operations maybecome more volatile, and our cash flows maybeless predictable, whichcould adversely affectour ability to plan for, and fund, our capital expenditure requirements. Anyofthese consequencescould have amaterial and adverse effect on our business, financial condition and resultsofoperations.

RisksRelated to COVID-19, Cybersecurity and OtherExternal Factors

Outbreaks of communicablediseases can adverselyaffect ourbusiness, financial condition andresults of operations.

Globalornational healthconcerns, includingawidespreadoutbreakofcontagious disease,can,among other impacts, negatively impact theglobal economy, reducedemand and pricing for crude oil,natural gasand NGLs,lead to operational disruptions and limit ourability to executeonour business plan, any of which couldmateriallyand adversely affect our business, financial condition and results of operations. Furthermore,uncertaintyregarding the impact of any outbreakof contagious disease could lead to increasedvolatility in crude oil,natural gas andNGL prices.

23 For example, the current pandemicinvolving ahighlytransmissibleand pathogeniccoronavirus (COVID-19) andthe measuresbeing taken to address and limit the spread of thevirus have adversely affectedthe economies and financialmarkets of the world, resultinginaneconomicdownturn thathas negatively impacted,and maycontinue to negatively impact, global demand and prices forcrude oil,naturalgas andNGLs. In fact, the substantial declines in crudeoil,natural gas andNGL pricesthatoccurred in the first half of 2020 as aresult of the economic downturn and overall reduction of demand prompted by the COVID-19 pandemic(and the oversupplyofcrude oilfromcertain foreignoil-exporting countries) materially and adversely affected the amount of cash flows we had available for our 2020 capital expenditures and otheroperating expenses, our results of operations duringthe first half of 2020 andthe trading price of our commonstock.

While in thesecond half of 2020 theprices for natural gasand NGLs recoveredtopre-pandemiclevels and theprices for crude oil increased from their first half 2020 levels, if such price declinesweretoreoccur and continue for an extended period of time,our cash flows and results of operations would be furtheradversely affected, as couldthe trading price of our common stock. For furtherdiscussion regarding the potentialimpacts on us of lower commodity pricesand extended declines in commodityprices, see the related discussion in the firstrisk factor in this section.

Further, if the COVID-19outbreakshouldcontinue or worsen, we mayalsoexperience disruptions to commodities markets, equipment supplychains andthe availability of our workforce,whichcouldmateriallyand adverselyaffectour ability to conductour business andoperations. In addition, if the resulting economicdownturn should continue or worsen, our customers and othercontractual partiesmay be unabletopay amounts owed to us from time to time and to otherwisesatisfy their contractualobligations to us, and maybeunabletoaccessthe credit andcapital markets for such purposes.Suchinability of our customers and othercontractualcounterparties maymaterially and adversely affect ourbusiness, financial condition, results of operations andcash flows.

There are stilltoo many variablesand uncertainties regarding theCOVID-19 pandemic,including the duration and severityofthe outbreak and the extent of travel restrictions and business closuresimposedinaffected countries, to fully assess the potential impactonour business, financial condition and results of operations.

Our business couldbemateriallyand adversely affected by security threats, includingcybersecurity threats, andother disruptions.

As an oil andgas producer, we face various security threats, including (i) cybersecurity threats to gain unauthorized access to, or control of, our sensitive information or to render ourdataorsystems corrupted or unusable;(ii)threats to the security of ourfacilitiesand infrastructure or to the security of third-party facilities and infrastructure, suchasgathering, transportation, processing,fractionation, refining andexportfacilities; and(iii) threatsfromterroristacts. The potential for such security threatshas subjectedour operations to increased risksthatcould have amaterial and adverseeffect on our business.

We relyextensively on information technology systems, including internallydeveloped software,data hosting platforms, real-time data acquisition systems, third-partysoftware, cloud servicesand otherinternally or externally hosted hardwareand software platforms, to (i) estimateour oil andgas reserves,(ii)process and record financial andoperatingdata, (iii) process and analyze all stagesofour business operations, including exploration, drilling, completions, production, transportation, pipelines and other related activities and (iv) communicate withour employeesand vendors, suppliers andother third parties. Although we have implemented and invested in, and willcontinuetoimplementand invest in, controls, procedures and protections(including internaland externalpersonnel) thatare designed to protect oursystems, identify and remediateonaregular basis vulnerabilitiesinour systems and related infrastructure andmonitor and mitigatethe risk of data loss and othercybersecuritythreats, such measurescannotentirely eliminate cybersecuritythreats andthe controls, procedures and protections we have implemented andinvestedinmay prove to be ineffective.

Our systems and networks, and those of our business associates, maybecome the target of cybersecurity attacks, including, without limitation, denial-of-service attacks;malicious software;data privacy breaches by employees, insiders or others withauthorized access; cyberorphishing-attacks; ransomware;attempts to gainunauthorized access to ourdataand systems;and otherelectronic security breaches. If any of these security breaches were to occur,wecouldsuffer disruptions to ournormal operations, including ourdrilling,completion, production and corporate functions, which could materially and adversely affect us in avarietyofways,including, but not limited to,the following:

24 • unauthorized access to, and release of, our business data, reservesinformation, strategic informationorother sensitive or proprietary information, whichcouldhaveamaterial andadverse effect on our abilitytocompete for oil andgas resources,orreduceour competitive advantage over othercompanies; • datacorruption, communication interruption,orother operational disruptions during our drilling activities, which couldresult in our failure to reachthe intendedtargetoradrillingincident; • datacorruption or operationaldisruptions of our production-relatedinfrastructure, whichcould resultinlossof production or accidentaldischarges; • unauthorized access to, and releaseof, personalinformation of our royalty owners, employees and vendors, which couldexpose us to allegations thatwedid notsufficiently protectsuch information; • acybersecurityattack on avendor or serviceprovider, which couldresult in supply chain disruptions and coulddelay or halt our operations; • acybersecurity attack on third-partygathering, transportation,processing, fractionation,refining or export facilities, whichcould result in reduceddemand for our production or delayorprevent us from transportingand marketing our production, in eithercaseresulting in aloss of revenues; • acybersecurityattackinvolving commodities exchangesorfinancial institutionscouldslow or halt commodities trading,thus preventing us from marketing our production or engaging in hedging activities, resulting in alossof revenues; • adeliberatecorruption of ourfinancial or operating data couldresultinevents of non-compliancewhichcould then lead to regulatoryfines or penalties; • acybersecurityattackonacommunications network or power grid,whichcouldcause operational disruptions resultinginaloss of revenues; and • acybersecurityattackonour automatedand surveillancesystems, which couldcause aloss of production and potential environmental hazards.

Further, strategictargets,such as energy-related assets, maybeatagreaterriskofterrorist attacks or cybersecurity attacks than othertargets in theUnitedStates. Moreover, external digitaltechnologies controlnearly all of thecrude oil and natural gasdistributionand refining systemsinthe U.S. and abroad, which are necessary to transport and marketour production. Acybersecurity attack directedat, for example,crude oiland natural gasdistribution systems could(i) damage criticaldistribution and storage assetsorthe environment; (ii) disruptenergy suppliesand markets, by delaying or preventing delivery of production to markets; and(iii) make it difficultorimpossible to accurately account for production andsettle transactions.

Any such terrorist attackorcybersecurityattackthataffectsus, our customers, suppliers, or others withwhomwedo business and/or energy-related assetscouldhave amaterial adverse effect on ourbusiness, including disruption of our operations, damage to our reputation, aloss of counterparty trust,reimbursement or othercosts, increased compliancecosts, significant litigation exposure andlegal liability or regulatory fines, penalties or intervention. Although we have business continuity plans in place, our operations maybeadversely affected by significant andwidespreaddisruption to our systemsand theinfrastructure thatsupports our business. Whilewecontinuetoevolve and modify our business continuity plans as wellas our cyberthreatdetectionand mitigationsystems, there can be no assurance thatthey willbeeffective in avoiding disruption and business impacts.Further, our insurancemay not be adequate to compensate us for allresultinglosses, and the cost to obtain adequate coverage mayincrease for us in the future andsome insurance coverage maybecome moredifficult to obtain, if available at all.

While we have experienced limited cybersecurityattacksinthe past, we have not sufferedany lossesasaresult of such attacks; however, there is no assurance thatwewillnot suffer such lossesinthe future.Further,astechnologiesevolve and cybersecuritythreatsbecome more sophisticated,weare continually expending additional resources to modify or enhance our security measures to protect against such threats and to identifyand remediateonaregular basisany vulnerabilities in our informationsystems and related infrastructurethatmay be detected, andthese expenditures in the future may be significant. Additionally, the continuing and evolving threatofcybersecurityattackshas resulted in evolving legal and compliancematters, including increased regulatoryfocus on prevention, which couldrequire us to expend significant additional resources to meet such requirements.

25 Terrorist activitiesand military andotheractions could materiallyand adverselyaffect us.

Terroristattacks and the threatofterrorist attacks(including cyber-related attacks),whether domesticorforeign, as wellasmilitaryorotheractions takeninresponse to these acts,could cause instability in theglobalfinancial and energy markets. The U.S.governmenthas from timetotimeissuedpublicwarnings thatindicatethatenergy-related assets, suchas transportation andrefining facilities, might be specifictargets of terrorist organizations.

Any such actions andthe threat of such actions, including anyresulting political instabilityorsocietal disruption,could materially and adversely affectusinunpredictable ways, including, but not limitedto, the disruption of energy supplies and markets, the reduction of overall demand for crude oiland natural gas, increased volatility in crude oiland natural gaspricesor the possibility that thefacilities and otherinfrastructure on whichwerely could be adirect target or an indirectcasualtyofan actofterrorism,and, in turn,could materiallyand adversely affect our business,financial condition and resultsofoperations.

Weather and climate mayhave asignificant andadverse impactonus.

Demandfor crude oiland naturalgas is, to adegree, dependent on weather and climate, whichimpacts,among other things, the pricewereceivefor the commoditiesthatweproduce and, in turn,our cash flows andresultsofoperations. For example,relatively warm temperaturesduring awinter season generally resultinrelatively lower demand for natural gas (as lessnatural gasisusedtoheatresidences and businesses)and,asaresult, lower pricesfor natural gasproduction during that season.

In addition, there has beenpublicdiscussion thatclimate changemay be associated with more frequent or more extremeweather events,changes in temperature and precipitationpatterns, changestogroundand surface wateravailability, and otherrelated phenomena, which could affect some, or all, of our operations. Our exploration, exploitation and development activities and equipmentcouldbeadversely affectedbyextremeweatherevents, suchaswinter storms, flooding and tropicalstorms and hurricanesinthe , whichmay cause aloss of production from temporary cessation of activity or damagedfacilitiesand equipment. Such extreme weathereventscouldalso impactother areas of our operations, including access to ourdrilling and production facilitiesfor routine operations, maintenance andrepairs, the installationand operation of gathering, processing, compression, storage,transportation and/or exportfacilities and the availabilityof, andour access to, necessary third-partyservices, such as gathering, processing, compression, storage andtransportation servicesand export services. Suchextreme weathereventsand changes in weather patterns maymaterially and adversely affect our business and, in turn,our financialcondition andresultsofoperations.

ITEM1B. UnresolvedStaff Comments

Notapplicable.

ITEM2. Properties

Oiland Gas Exploration and Production -Propertiesand Reserves

ReserveInformation. For estimates and discussions of EOG's netprovedreserves of crude oiland condensate,natural gasliquids(NGLs)and natural gas, the qualifications of the preparers of EOG's reserve estimates,EOG's independent petroleum consultantsand EOG'sprocesses and controls withrespect to its reserve estimates, see "Supplemental Informationto ConsolidatedFinancialStatements."

There are numerous uncertainties inherent in estimating quantitiesofprovedreserves and in projecting future rates of productionand timing of development expenditures, including many factorsbeyond the controlofthe producer.The reserve data setforthin"Supplemental Information to Consolidated FinancialStatements" represent only estimates. Reserve engineering is acomplex, subjective process of estimating underground accumulations of crude oil andcondensate, NGLsand natural gas thatcannot be measuredinanexact manner.The accuracy of any reserveestimate is afunction of the amount and quality of available dataand of engineering andgeological interpretationand judgment.Asaresult, estimates by different engineers normally vary.Inaddition, results of drilling, testing and production or fluctuations in commoditypricessubsequent to the dateofanestimatemay justify revision of such estimate(upward or downward). Accordingly, reserve estimates are often different from the quantitiesultimatelyrecovered. Further, the meaningfulness of suchestimates is highlydependent upon the accuracyofthe assumptions upon which theywerebased.For related discussion, see ITEM 1A, Risk Factors, and "SupplementalInformationtoConsolidatedFinancialStatements."

26 In general, the rateofproduction from crude oil andnaturalgas propertiesdeclinesasreservesare produced. Except to the extent EOG acquires additional propertiescontaining proved reserves, conducts successfulexploration, exploitation and development activities or,through engineering studies,identifiesadditional behind-pipe zones or secondary recovery reserves, the proved reserves of EOG will declineasreservesare produced. Future production is, therefore, highly dependent upon the levelofsuccess of these activities.For related discussion, see ITEM 1A, Risk Factors. EOG'sestimates of reserves filed with otherfederal agencies are consistent with theinformationset forthin"Supplemental Information to Consolidated Financial Statements."

Acreage. Thefollowing table summarizesEOG's grossand net developedand undevelopedacreage at December 31, 2020. Excluded is acreage in whichEOG's interest is limited to ownedroyalty,overriding royaltyand other similarinterests.

Developed Undeveloped Total Gross NetGrossNet Gross Net

United States 2,528,907 1,887,080 2,871,470 1,983,209 5,400,377 3,870,289 Trinidad 79,410 67,580 201,302 115,168 280,712 182,748 China130,548 130,548 ——130,548 130,548 Canada 30,771 27,513 19,197 19,197 49,968 46,710 Oman ——8,400,348 7,828,089 8,400,348 7,828,089 Total 2,769,6362,112,721 11,492,317 9,945,663 14,261,953 12,058,384

Most of our undevelopedoil andgas leases, particularlyinthe United States, are subject to leaseexpiration if initial wells are notdrilled within aspecifiedperiod, generally between threetofiveyears. Approximately 0.2million net acres will expire in 2021,0.2 million net acres will expire in 2022 and0.1 million net acres will expire in 2023 if production is not established or we take no other actiontoextend the termsofthe leases or obtain concessions. As of December31, 2020, there were no proved undevelopedreserves(PUDs)associated with such undeveloped acreage. In the ordinary course of business, basedonour evaluations of certain geologictrendsand prospective economics, we have allowed certainlease acreagetoexpire and may allow additional acreage to expire in thefuture.

Many of our oil andgas leasesare largeenoughtoaccommodate more thanone producing unit. Included in our undeveloped acreage is non-producing acreage withinsuch largerproducing leases.

The agreement governing the acreageassociated with ourexploration program in Oman is set to expire in 2024, with certain provisions allowingfor extension of suchtermifcommercial discoveries arefound.

Productive WellSummary.The following tablerepresentsEOG's gross and netproductive wells, including2,482 wells in whichwehold aroyalty interest. Crude OilNatural Gas Total Gross NetGrossNet Gross Net

United States 9,6586,724 3,985 1,942 13,643 8,666 Trinidad2133273528 China ——36363636 Canada —— 1— 1— Total (1) 9,660 6,725 4,055 2,005 13,715 8,730

(1) EOG operated 9,491 gross and 8,394 net producing crude oil and naturalgas wells at December 31, 2020. Gross crude oil and natural gas wells include142 wells with multiplecompletions.

27 Drilling and AcquisitionActivities.During the yearsended December 31,2020, 2019 and 2018, EOGexpended $3.7 billion, $6.6 billion and$6.4 billion, respectively, forexploratory and development drilling, facilities andacquisition of leases and producing properties,including asset retirementobligations of $117 million, $186 millionand $70 million, respectively. The following tables set forththe resultsofthe gross crude oiland natural gaswells completed for the years ended December 31, 2020, 2019 and2018: Gross Development Wells Completed Gross ExploratoryWells Completed Crude Natural Dry Hole Crude Natural DryHole Oil Gas Total Oil Gas Total 2020 UnitedStates580 13 15 608 3— 47 Trinidad————— 3— 3 China ———————— Total 580 13 15 608 33410 2019 United States 8332614873 4— 15 Trinidad —1—1—— 11 China —2—2—— 11 Total 833 29 14 876 4— 37 2018 UnitedStates834 39 22 895 —— 11 Trinidad ———————— China—1— 1— 2— 2 Total 834 40 22 896— 213

The following tablesset forth the resultsofthe netcrude oil andnatural gaswells completedfor the years ended December 31, 2020, 2019 and 2018: NetDevelopment Wells CompletedNet Exploratory Wells Completed Crude Natural Dry Hole Crude Natural DryHole Oil Gas Total Oil Gas Total 2020 UnitedStates516 12 15 543 2— 35 Trinidad————— 2— 2 China ———————— Total 516 12 15 543 2237 2019 UnitedStates 721 22 12 755 4— 15 Trinidad —1—1—— 11 China —2—2—— 11 Total 721 25 12 758 4— 37 2018 UnitedStates704 37 18 759 —— 11 Trinidad ———————— China—1— 1— 2— 2 Total 7043818760 —213

28 EOGparticipated in thedrilling of wells thatwereinthe process of being drilled or completedatthe end of the period as setout in thetable below for theyears ended December31, 2020, 2019 and 2018: Wells in Progress at EndofPeriod 2020 2019 2018 GrossNet Gross NetGross Net

United States 155147 317286 297 238 Trinidad 1111—— China 333344 Oman 11———— Total 160152 321290 301242

Included in the previous table of wellsinprogress at theend of the period were wells which hadbeendrilled, but were not completed (DUCs).Inorder to effectively manage itscapital expenditures and to provide flexibilityinmanaging its drilling rig and wellcompletion schedules, EOG, from time to time,will have an inventory of DUCs. At December31, 2020,there were approximately84MMBoeofnet PUDs associated with EOG's inventory of DUCs. Under EOG's current drilling plan, all such DUCsare expectedtobecompleted within five yearsfromthe original booking date of suchreserves. Thefollowing table sets forth EOG'sDUCs, forwhich PUDs hadbeenbooked, as of theend of each period. Drilled Uncompleted WellsatEnd of Period 2020 2019 2018 GrossNet Gross NetGross Net

United States 89 86 188165 168 137 China 333333 Total 92 89 191168 171 140

EOG acquired wellsasset forth in the following tablesasofthe endofeachperiod(excluding the acquisitionof additional interests in 8, 11 and 114 netwells in which EOG previously ownedaninterest forthe years endedDecember 31, 2020, 2019 and 2018, respectively):

Gross AcquiredWells NetAcquiredWells Crude Natural Crude Natural Oil Gas Total Oil Gas Total 2020 UnitedStates80383 70 373 Total 80 38370373 2019 UnitedStates 94554937 46 Total 94554937 46 2018 UnitedStates15132810616 Total 15 13 28 10 616

OtherProperty,Plant and Equipment. EOG's otherproperty, plant andequipment primarily includes gathering, transportation and processing infrastructure assets, buildings and sand processing assetswhichsupport EOG's exploration and production activities.EOG doesnot own drilling rigs, hydraulic fracturing equipment or railcars. All of EOG'sdrilling and completionactivities are conducted on acontractualbasis with independent drilling contractors and otherthird-party service contractors.

29 ITEM3. Legal Proceedings

See the informationset forth under the "Contingencies" caption in Note 8ofthe NotestoConsolidated Financial Statements,which is incorporatedbyreference herein.

Item103 of Regulation S-Kpromulgatedunderthe SecuritiesExchange Actof1934, as amended, requires disclosure regarding certainproceedings arising under federal, stateorlocal environmental laws when agovernmental authority is aparty to theproceedings and suchproceedings involve potential monetary sanctions thatEOG reasonably believes will exceeda specified threshold. Pursuant to recentamendments to this item, EOG will be using athreshold of $1 million for purposes of determining whetherdisclosure of any such proceedings is required; EOG believes proceedings underthis thresholdare not material to EOG's business andfinancialcondition. Applying thisthreshold,there are no environmental proceedings to disclose forthe quarterand year endedDecember 31,2020.

ITEM4. Mine Safety Disclosures

The informationconcerning mine safetyviolations and otherregulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform andConsumer ProtectionAct and Item 104ofRegulation S-K (17 CFR 229.104) is included in Exhibit 95 to thisreport.

PART II

ITEM5. Marketfor Registrant's Common Equity, RelatedStockholder Matters and Issuer PurchasesofEquity Securities

EOG'scommon stockistradedonthe NewYork Stock Exchange underthe tickersymbol "EOG."

As of February 12, 2021, there were approximately2,060 record holders and approximately 321,000 beneficialowners of EOG's commonstock.

The following table sets forth, for theperiods indicated, EOG's share repurchase activity:

(c) (a) Total Number of (d) Total (b) Shares Purchased as Maximum Number Numberof Average Part of Publicly of Shares that May Yet Shares Price Paid Announced Plans or Be Purchased Under Period Purchased (1) per Share Programs the Plans or Programs (2)

October1,2020 -October 31, 2020 3,892 $34.56 — 6,386,200 November1,2020 -November 30, 2020 3,678 41.84 — 6,386,200 December1,2020 -December 31, 2020 19,548 52.21 — 6,386,200 Total27,118 $48.27

(1) The 27,118 total shares for the quarter ended December 31, 2020, and the 389,613 total shares for the full year 2020,consist solely of shares that were withheldbyorreturned to EOG (i) in satisfaction of tax withholding obligations thatarose uponthe exercise of employee stock options or stock-settled stock appreciation rights or the vesting of restricted stock, restricted stockunitorperformance unitgrants or (ii) in payment of the exercise price of employeestock options. These shares do not count against the10million aggregate share repurchase authorization of EOG'sBoard discussedbelow. (2) In September 2001, the Board authorized the repurchase of up to 10,000,000sharesofEOG's common stock. During 2020, EOG did not repurchase any shares under the Board-authorized repurchase program.EOG last repurchasedshares under thisprogram in March 2003.

30 Comparative Stock Performance

The following performancegraph and related information shallnot be deemed"soliciting material" or to be "filed" withthe UnitedStates Securitiesand Exchange Commission, nor shallsuchinformation be incorporated by reference into any future filingunder the Securities Actof1933, as amended, or SecuritiesExchange Act of 1934, as amended, except to the extent thatEOG specifically requeststhat suchinformationbetreated as "solicitingmaterial" or specifically incorporatessuch informationbyreferenceinto suchafiling.

Theperformance graphshown below comparesthe cumulative five-yeartotal return to stockholders on EOG's common stockascompared to the cumulative five-yeartotalreturns on the Standard andPoor's500 Index (S&P 500) andthe Standard and Poor's 500 Oil &Gas Exploration &ProductionIndex (S&P O&GE&P).The comparison wasprepared based upon the following assumptions:

1. $100 was invested on December 31, 2015 in each of the following: common stockofEOG, the S&P500 andthe S&P O&G E&P. 2. Dividends arereinvested.

Comparison of Five-Year Cumulative TotalReturns EOG, S&P500 and S&PO&G E&P (PerformanceResults Through December 31, 2020)

$300.00

EOGResources Inc.

Standard&Poors500

S&P O&GExpl&Prod

$203.05 $200.00

$171.49 $154.79 $144.04 $136.40 $130.42 $132.83 $125.91 $124.46 $122.37 $100.00 $111.96 $112.23 $100.00 $100.19

$74.85 $73.61

$0.00 2015 2016 2017 2018 2019 2020

2015 2016 2017 2018 2019 2020 EOG$100.00 $144.04$ 154.79 $125.91$ 122.37 $74.85 S&P500 $100.00 $111.96$ 136.40 $130.42$ 171.49 $203.05 S&PO&G E&P$100.00 $132.83$ 124.46 $100.19$ 112.23 $73.61

31 ITEM6. Selected Financial Data (In Thousands, Except Per ShareData)

The following selected consolidatedfinancialinformation shouldbereadinconjunction withITEM7,Management's Discussion and AnalysisofFinancial Condition andResults of Operationsand ITEM 8, Financial Statements and Supplementary Data. Year EndedDecember 31 2020 2019 2018 2017 2016

StatementofIncomeData: (1) OperatingRevenues andOther $11,032,048 $17,379,973 $17,275,399 $11,208,320 $7,650,632 OperatingIncome(Loss) $(544,016) $3,699,011 $4,469,346 $926,402 $(1,225,281) NetIncome (Loss) $(604,572) $2,734,910 $3,419,040 $2,582,579 $(1,096,686) NetIncome (Loss) PerShare Basic $(1.04) $4.73$ 5.93 $4.49$ (1.98) Diluted $(1.04) $4.71 $5.89 $4.46$ (1.98) Dividends Per CommonShare $1.50 $1.0825$ 0.81 $0.67$ 0.67 Average NumberofCommon Shares Basic 578,949 577,670 576,578 574,620 553,384 Diluted 578,949 580,777 580,441 578,693 553,384

At December312020 2019 2018 2017 2016

Balance Sheet Data: Total Property, Plant andEquipment, Net $28,598,627 $30,364,595 $28,075,519 $25,665,037 $25,707,078 Total Assets (2) (3) (4) 35,804,601 37,124,608 33,934,474 29,833,078 29,299,201 Total Debt 5,816,405 5,175,443 6,083,262 6,387,071 6,986,358 Total Stockholders' Equity 20,301,887 21,640,716 19,364,188 16,283,273 13,981,581

(1) Effective January 1, 2018, EOG adoptedthe provisions of Accounting StandardsUpdate(ASU) 2014-09, "Revenue From Contracts With Customers" (ASU 2014-09). In connection with the adoption of ASU 2014-09, EOG presents natural gas processing feesrelating to certain processingand marketingagreements withinits UnitedStates segment as Gathering andProcessing Costs instead of as a deduction to Natural Gas Revenues. There was no impact to operating income, net income or cash flows resulting from changes to the presentation of natural gas processing fees. EOGelectedtoadopt ASU 2014-09 using the modified retrospective approachwith no reclassification of amounts forthe years ended December 31, 2017 and 2016(see Note 1toConsolidated Financial Statements). (2) Effective January 1, 2020, EOG adopted the provisions of ASU 2016-13, "MeasurementofCredit Losses on Financial Instruments" (ASU 2016-13). ASU 2016-13 changes the impairment model for financial assets and certain other instruments by requiring entitiestoadopt aforward-looking expectedloss model that will result in earlier recognition of credit losses. EOG electedto adopt ASU 2016-13 using the modified retrospective approach with acumulative-effectadjustment to retainedearningsasofthe effective date. Financial results reportedinperiods prior to January1,2020, are unchanged. There was no impact to retained earnings uponadoptionofASU 2016-13 and EOG expects current and future creditlosses to be immaterial.EOG continues to monitor the credit risk from third-party companies to determine if expected credit losses maybecome material. (3) Effective January1,2019,EOG adopted the provisionsofASU 2016-02,"Leases (Topic 842)" (ASU 2016-02), which require that lessees recognizearight-of-use (ROU) asset and related lease liability,representingthe obligation to make lease payments of certain lease transactions, on the Consolidated Balance Sheets. EOG elected to adopt ASU 2016-02 and other related ASUs using the modified retrospective approach with acumulative-effect adjustment to the opening balance of retainedearningsasofthe effective date. Financial results reported in periodsprior to January 1, 2019, are unchanged. There was no impacttoretainedearnings upon adoptionofASU 2016-02 and other related ASUs. See Notes 1and 18 to Consolidated Financial Statements. (4) Effective January 1, 2017, EOG adoptedthe provisionsofASU 2015-17, "IncomeTaxes (Topic 740): Balance Sheet Classification of DeferredTaxes" (ASU 2015-17), which simplifies the presentation of deferred taxes in aclassified balance sheet by eliminating the requirement to separate deferred income tax liabilitiesand assets into currentand noncurrent amounts. Instead, ASU 2015-17 requires thatall deferred tax liabilitiesand assetsbeshown as noncurrentinaclassified balance sheet. In connectionwiththe adoption of ASU 2015-17, EOG restated $160 million from deferred tax liabilities to deferredtax assets on its Consolidated Balance SheetatDecember 31, 2016.

32 ITEM7. Management'sDiscussion and AnalysisofFinancialCondition and ResultsofOperations

Overview

EOG Resources, Inc., togetherwithits subsidiaries (collectively,EOG), is oneofthe largestindependent (non- integrated)crude oiland naturalgas companies in theUnited States withprovedreserves in theUnitedStates,Trinidadand China. EOG operatesunder aconsistent business and operationalstrategythatfocuses predominantly on maximizing therate of return on investment of capital by controlling operating and capitalcosts and maximizing reserve recoveries. Pursuant to this strategy, each prospectivedrilling location is evaluatedbyits estimated rate of return. This strategy is intended to enhancethe generation of cash flow andearnings from each unit of production on acost-effective basis, allowing EOG to deliver long-term growth in shareholder value andmaintain astrong balance sheet. EOGimplements its strategyprimarily by emphasizing the drilling of internally generated prospects in order to find and develop low-cost reserves. Maintainingthe lowest possible operating cost structure, coupled withefficient andsafe operations and robust environmental stewardshippractices and performance, is integral in theimplementation of EOG's strategy.

EOG realizedanet lossof$605 millionduring2020ascompared to netincomeof$2,735 million for 2019. At December 31, 2020, EOG's totalestimated netprovedreserves were 3,220 million barrels of oil equivalent (MMBoe), a decrease of 109 MMBoe from December 31, 2019. During 2020, netprovedcrude oil andcondensateand naturalgas liquids (NGLs)reserves decreased by 108 million barrels (MMBbl), andnet proved naturalgas reserves decreased by 9billion cubic feet or 1MMBoe,ineachcase from December 31, 2019.

Recent Developments

CommodityPrices. The COVID-19 pandemic andthe measures being takentoaddress and limitthe spread of the virushaveadversely affected the economies and financialmarkets of the world, resulting in an economic downturn thathas negatively impacted, and maycontinue to negatively impact,global demandand prices for crude oiland condensate, NGLs and natural gas. SeeITEM1A, Risk Factors for further discussion.

In earlyMarch 2020, due to the failureofthe members of the Organizationofthe Petroleum Exporting Countriesand Russia (OPEC+) to reach an agreement on individualcrude oilproduction limits,Saudi Arabia unilaterally reduced the sales price of its crude oiland announcedthatitwouldincrease its crude oil production. The combination of these actions, and the effects of the COVID-19 pandemiconcrude oil demand, resultedinsignificantly lowercommodity prices in Marchand April 2020. In April2020, the membersofOPEC+ reachedanagreement to cut crude oilproduction beginning in May 2020 and extending through April 2022 with the quantityofthe productioncutsdecreasing overtime. Subsequent indications of conformitywiththese agreed-upon production cutsbyOPEC+,combined withthe evolving impacts of COVID-19 on crude oil demand, have resulted in gradually-improving market conditions. In thesecond half of 2020, crude oilpricesincreased,but remain significantlybelow average prices in 2019, as aresultofthe continuingrebalancing of crude oil supplyresulting from the actionsofOPEC+and the continuing effectofthe COVID-19 pandemic on global demand.Inaddition, NGL andnatural gas priceshaverecovered to pre-pandemic levels.

In response to thecommodityprice environment in 2020,EOG reducedactivity across itsoperating areasand decreasedits total capital expenditures. EOGalso electedtoreducecrude oilproduction, by delaying initial productionfrom new wells and shutting-in or otherwise curtailing existing production.

In early2021, the members of OPEC+ met andagreed to taper offcertain of their production curtailments (agreedtoin April 2020) through March2021. Subsequent to the meeting, Saudi Arabiaannounced thatitwould unilaterally cut its production by an additionalone million barrelsper day in February 2021 and March 2021. These announcementshave had a positive impact on crude oil prices.

As aresult of the many uncertainties associatedwith(i) the world economicenvironment,(ii)the COVID-19 pandemicand its continuing effectonthe economies and financial markets of theworld and (iii) any futureactions by the members of OPEC+,and the effectofthese uncertainties on worldwide supplies of, and demand for, crude oiland condensate, NGLs and natural gas, EOG is unabletopredict whatchangesmay occur in crude oiland condensate,NGLsand naturalgas prices in thefuture. However, pricesfor crude oiland condensate, NGLs andnatural gashave historicallybeen volatile,and this volatilityisexpectedtocontinue.For relateddiscussion, see ITEM 1A, Risk Factors.

EOG will continue to monitor futuremarketconditions and adjust its capital allocationstrategyand production outlook accordinglyinorder to maximize shareholder value while maintaining itsstrong financialposition.

33 2020 Election. In November2020, Joseph R. Biden Jr. was elected President of the UnitedStates. On January 27, 2021, President Bidenissued Executive Order14008 entitled "Tacklingthe Climate Crisis at Home andAbroad," directing the Secretaryofthe Interior, to the extent consistent with applicablelaw and in consultationwithotheragencies andstakeholders, to (i) pause approval of newoil andnaturalgas leases on federal landsorinoffshore waters pending completion of a comprehensive review and reconsideration of federal oiland gaspermitting and leasing practices and (ii) consider whetherto adjust royaltiesassociatedwithoil andgas resourcesextractedfromfederal landsand offshore waters to account for corresponding climate costs. In addition, neworrevisedrules,regulationsand policiesmay be issued, andnew legislationmay be proposed, during the current administration thatcould impactthe oiland gasexploration andproduction industry. Such rules, regulations, policies andlegislation mayaffect,among otherthings,(i) permittingfor oil andgas drilling on federallands, (ii) theleasingoffederal lands for oil andgas development,(iii) the regulationofgreenhouse gasemissions and/or other climate change-related mattersassociatedwithoil andgas operations,(iv)the use of hydraulicfracturing on federal lands, (v) the calculationofroyalty payments in respect of oil and gas production from federal landsand (vi) U.S. federal income taxlaws applicable to oiland gasexploration and production companies. See "Regulation"inITEM 1, Business and ITEM 1A, Risk Factors for furtherdiscussion.

EOG will continue to monitor and assess anyactions thatcould impact the oil andgas industry, to determinethe impactonits business and operations, andtakeappropriate actions where necessary.

Operations

Several important developments have occurred sinceJanuary 1, 2020.

United States. EOG's effortstoidentify plays withlarge reserve potential have proven to be successful.EOG continues to drillnumerous wells in large acreageplays, whichinthe aggregate havecontributed substantially to,and are expected to continuetocontributesubstantially to,EOG's crude oiland condensate, NGLs and natural gasproduction. EOG has placedanemphasisonapplying itshorizontal drilling and completion expertise to unconventional crudeoil andliquids-rich reservoirs.

During 2020, EOGcontinuedtofocus on increasing drilling, completion and operating efficienciesgained in prior years. Suchefficiencies, combinedwithnew innovationand decreased service costs, resultedinlower operating, drilling and completioncostsin2020. In addition, EOG continuedtoevaluate certainpotential crude oiland condensate,NGLs and natural gasexplorationand development prospectsand to look for opportunitiestoadd drilling inventory through leasehold acquisitions, farm-ins,exchangesortactical acquisitions. On avolumetric basis,ascalculated usingaratio of 1.0 barrelof crude oiland condensate or NGLsto6.0 thousand cubicfeet of natural gas, crude oiland condensateand NGLs production accounted forapproximately 76% and 77% of United Statesproduction during 2020 and 2019, respectively.During2020, drilling and completion activitiesoccurred primarilyinthe DelawareBasin play, Eagle Ford playand Rocky Mountain area. EOG'smajorproducing areas in the UnitedStatesare in New Mexico and Texas.Inthe second quarter of 2020, EOGdelayed initial production from most newly-completedwells and shut in someexisting production. During the third quarter of 2020, EOG resumed the process of initiating productionfromcompletedwells,and the legacywells that were shut-in were largely brought back on-line.See ITEM 1, Business -Exploration and Production for further discussion.

Trinidad. In Trinidad, EOGcontinuestodelivernaturalgas under existing supply contracts. Several fields in the SouthEastCoast Consortium Block, ModifiedU(a)Block, Block4(a), Modified U(b) Block, the BanyanField andthe Sercan Areahave been developed and are producing natural gas, which is sold to the National GasCompany of Trinidadand Tobago Limited andits subsidiary,and crude oiland condensate which is sold to Heritage Petroleum Company Limited.

In 2020,EOG drilledthreenet wells and completed two netwells in Trinidad. Theremaining net well made a discovery thatisbeing evaluated.

Other International. In theSichuan Basin,Sichuan Province, China,EOG continues to work with its partner, PetroChina, under the Production Sharing Contractand otherrelated agreements, to ensure uninterruptedproduction. All natural gas produced from theBaijaochang Field is sold underalong-term contracttoPetroChina.

In 2020,EOG enteredinto two agreements relatedtoexploration and production rights in theSultanateofOman (Oman). Oneagreement resulted in EOG acquiringexploration and production rightstoBlock 36 withinOman. The second agreement wasafarm-in agreement allowingEOG to share in explorationand production rightswithin Block49. Pursuant to that agreement, EOGparticipated in thedrillingofone gross exploratory wellwhich wasinprogress as of December31, 2020.

In March 2020, EOG beganthe process of exiting its Canada operations.

34 EOGcontinuestoevaluateotherselectcrude oil andnatural gasopportunities outside theUnited States, primarily by pursuing exploitation opportunities in countries whereindigenouscrude oiland natural gas reserveshavebeenidentified.

Capital Structure

One of management'skey strategies is to maintainastrong balance sheetwith aconsistently below averagedebt-to- total capitalizationratio as compared to those in EOG'speer group. EOG'sdebt-to-total capitalizationratio was22% at December 31, 2020 and 19% at December 31,2019. As usedinthis calculation, total capitalizationrepresentsthe sum of total current andlong-term debt andtotal stockholders' equity.

On April1,2020, EOG repaid upon maturity the $500 million aggregateprincipalamount of its 2.45%Senior Notes due 2020.

On April 14,2020, EOG closed on its offering of $750 million aggregateprincipal amount of its 4.375% Senior Notes due 2030 and $750 million aggregateprincipal amount of its 4.950% Senior Notesdue 2050 (together, the Notes). EOG receivednet proceedsof$1.48 billionfromthe issuance of the Notes, whichwereusedtorepaythe 4.40% Senior Notesdue 2020 when theymaturedonJune 1, 2020 (see below), and for general corporatepurposes, including the funding of capital expenditures.

On June 1, 2020, EOG repaid upon maturitythe $500 million aggregate principal amount of its4.40% Senior Notes due 2020.

On February 1, 2021, EOG repaid uponmaturity the$750 million aggregateprincipalamountofits 4.100% Senior Notesdue 2021.

During 2020, EOGfunded$4.0 billion ($386 million of which was non-cash) in exploration and development and otherproperty, plantand equipment expenditures (excludingassetretirement obligations), repaid $1.0 billion aggregate principalamount of long-term debtand paid $821 million in dividends to common stockholders, primarily by utilizingnet cash providedfromits operatingactivities, net proceedsof$1.48 billion from the issuance of the Notesand net proceeds of $192 million from the sale of assets.

Total anticipated2021 capital expenditures are estimated to range from approximately $3.7 billion to $4.1 billion, excluding acquisitionsand non-cash transactions. The majority of 2021 expenditures willbefocusedonUnitedStatescrude oil drilling activities.EOG has significant flexibilitywith respect to financing alternatives, includingborrowingsunder its commercial paper program, bank borrowings, borrowings under its senior unsecuredrevolving credit facility,jointdevelopment agreements andsimilaragreementsand equityand debt offerings.

Management continues to believe EOGhas one of the strongestprospect inventories in EOG's history. When it fits EOG's strategy, EOGwillmakeacquisitionsthatbolsterexisting drilling programsoroffer incremental exploration and/or production opportunities.

35 Results of Operations

The following reviewofoperations foreachofthe threeyearsinthe period endedDecember 31,2020, should be read in conjunctionwiththe consolidated financial statements of EOGand notestheretobeginning on page F-1.

Operating Revenuesand Other

During 2020, operating revenuesdecreased $6,348 million, or 37%, to $11,032million from $17,380 million in 2019. Total wellhead revenues, whichare revenues generated from sales of EOG's production of crude oiland condensate,NGLs and natural gas, decreased $4,291, or 37%, to $7,290 million in 2020 from $11,581 million in 2019.Revenues from thesales of crude oiland condensate andNGLs in 2020 were approximately 89%oftotal wellhead revenues comparedto90% in 2019. During 2020, EOG recognizednet gainsonthe mark-to-market of financial commodity derivative contracts of $1,145 million compared to net gainsof$180 millionin2019. Gathering, processing and marketing revenuesdecreased$2,777 million during 2020, to $2,583 million from $5,360 million in 2019.Net losses on assetdispositions of $47million in 2020 were primarily duetothe sales of provedproperties and non-cash property exchangesofunprovedleasehold in Texas and NewMexicoand the disposition of theMarcellusShaleassets comparedtonet gains on asset dispositions of $124 million in 2019.

36 Wellhead volume and price statistics forthe years ended December31, 2020, 2019 and 2018 were as follows: Year EndedDecember 31 2020 2019 2018

Crude Oiland Condensate Volumes(MBbld) (1) UnitedStates 408.1 455.5 394.8 Trinidad 1.00.6 0.8 OtherInternational (2) 0.10.1 4.3 Total 409.2 456.2 399.9 Average Crude Oiland CondensatePrices($/Bbl) (3) UnitedStates $38.65 $57.74 $65.16 Trinidad 30.2047.16 57.26 OtherInternational (2) 43.08 57.40 71.45 Composite 38.63 57.72 65.21 NaturalGas Liquids Volumes (MBbld) (1) UnitedStates 136.0 134.1 116.1 OtherInternational (2) ——— Total 136.0 134.1 116.1 Average NaturalGas Liquids Prices($/Bbl) (3) United States $13.41 $16.03 $26.60 OtherInternational (2) ——— Composite 13.41 16.03 26.60 NaturalGas Volumes(MMcfd) (1) UnitedStates 1,040 1,069 923 Trinidad 180 260 266 OtherInternational (2) 32 37 30 Total 1,252 1,366 1,219 Average NaturalGas Prices($/Mcf) (3) UnitedStates $1.61$ 2.22 $2.88 Trinidad 2.57 2.72 2.94 OtherInternational (2) 4.66 4.44 4.08 Composite 1.83 2.38 2.92 Crude OilEquivalent Volumes (MBoed) (4) UnitedStates 717.5 767.8 664.7 Trinidad 30.9 44.0 45.1 OtherInternational (2) 5.4 6.2 9.4 Total 753.8 818.0 719.2

Total MMBoe (4) 275.9 298.6 262.5

(1) Thousand barrels perday or million cubicfeet perday,asapplicable. (2) Other International includes EOG's UnitedKingdom, China and Canada operations. TheUnitedKingdom operations were soldinthe fourth quarterof2018. (3) Dollars per barrel or per thousand cubic feet, as applicable.Excludes the impact of financial commodity derivative instruments (see Note 12 to Consolidated Financial Statements). (4) Thousand barrels of oil equivalent per day or millionbarrelsofoil equivalent, as applicable;includes crude oil and condensate, NGLs and natural gas. Crude oil equivalent volumes are determinedusing aratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 thousand cubic feet of natural gas. MMBoe is calculated by multiplying the MBoedamount by the numberofdaysinthe period and thendividing that amount by one thousand.

37 2020 compared to 2019. Wellheadcrude oiland condensate revenues in 2020 decreased $3,827 million, or 40%, to $5,786 million from $9,613 million in 2019, due primarily to alower composite average wellhead crudeoil and condensate price($2,860 million)and adecreaseinproduction ($967 million). EOG'scompositewellhead crudeoil andcondensate price for 2020 decreased 33% to $38.63 perbarrelcompared to $57.72 per barrel in 2019. Wellhead crude oiland condensate production in 2020 decreased10% to 409 MBbldascompared to 456 MBbldin2019. The decreased production wasprimarily in theEagle Ford and theRocky Mountainarea,partially offsetbyincreased production in the PermianBasin.

NGLs revenues in 2020 decreased $116 million, or 15%, to $668 millionfrom$784 millionin2019 primarilydue to a lowercompositeaverage wellhead NGLs price($130 million), partially offsetbyanincrease in production ($13 million). EOG'scomposite average wellhead NGLs price decreased16% to $13.41 per barrelin2020comparedto$16.03per barrelin 2019. NGL production in 2020 increased 1% to 136MBbld as compared to 134 MBbld in 2019.The increasedproduction was primarily in the Permian Basin, partially offsetbydecreasedproductioninthe EagleFord.

Wellhead naturalgas revenuesin2020 decreased $347 million, or 29%, to $837 million from $1,184 million in 2019, primarily duetoalower composite wellhead naturalgas price ($251 million) and adecrease in natural gas deliveries ($96 million). EOG'scomposite averagewellheadnatural gasprice decreased23% to $1.83 per Mcfin2020compared to $2.38 per Mcf in 2019. Natural gasdeliveries in 2020 decreased8%to1,252 MMcfdascomparedto1,366 MMcfdin2019. The decrease in production wasprimarilydue to lower natural gas volumes in Trinidad, the Marcellus Shaleand theRocky Mountain area, partially offsetbyincreased production of associated natural gasfromthe PermianBasin.

During 2020, EOGrecognized net gainsonthe mark-to-marketoffinancialcommodity derivative contractsof$1,145 million, which included net cash received for settlementsofcrude oil,NGL andnatural gasfinancialderivativecontracts of $1,071 million. During 2019, EOG recognizednet gainsonthe mark-to-marketoffinancialcommodity derivative contractsof $180 million, which included netcashreceived for settlementsofcrude oil and natural gas financialderivativecontracts of $231 million.

Gathering, processing and marketing revenues are revenues generatedfromsales of third-partycrude oil, NGLs and natural gas,aswell as fees associatedwithgatheringthird-party natural gas andrevenuesfromsales of EOG-ownedsand. Purchases and sales of third-party crude oiland naturalgas maybeutilized in order to balancefirmtransportation capacity with production in certain areas and to utilize excess capacity at EOG-ownedfacilities. EOG sells sand in order to balancethe timing of firm purchase agreements withcompletion operations and to utilizeexcesscapacityatEOG-ownedfacilities. Marketing costs represent the coststopurchasethird-partycrude oil, natural gasand sand and the associated transportation costs, as well as costsassociatedwith EOG-ownedsand soldtothird parties.

Gathering, processing and marketing revenueslessmarketingcostsin2020decreased $124 millioncomparedto2019, primarily duetolowermargins on crude oiland condensate marketingactivities. Themarginoncrude oilmarketing activities in 2020 wasnegativelyimpacted by the price declinefor crudeoil in inventory awaiting delivery to customers and EOG's decision early in the second quarter of 2020 to reduce commodityprice volatility by selling May and June 2020 deliveries under fixedpricearrangements.

2019 comparedto2018. Wellhead crude oiland condensate revenues in 2019 increased $96 million, or 1%, to $9,613 million from $9,517 millionin2018, due primarily to an increaseinproduction ($1,351 million); partially offset by alower composite average wellhead crude oiland condensate price($1,255 million). EOG'scomposite wellhead crude oiland condensateprice for 2019 decreased11% to $57.72 per barrelcomparedto$65.21per barrelin2018. Wellhead crudeoil and condensateproduction in 2019 increased 14% to 456 MBbldascompared to 400 MBbld in 2018.The increased production was primarily in thePermianBasin andthe Eagle Ford.

NGLs revenuesin2019 decreased $343 million, or 30%, to $784 millionfrom$1,127 million in 2018 primarily dueto alower composite average wellhead NGLs price($518 million),partially offset by an increase in production ($175million). EOG'scomposite average wellhead NGLs pricedecreased40% to $16.03 perbarrelin2019compared to $26.60 perbarrel in 2018.NGL production in 2019 increased 16% to 134MBbld as compared to 116 MBbld in 2018. Theincreasedproduction was primarily in thePermianBasin.

Wellhead naturalgas revenuesin2019 decreased$118 million, or 9%, to $1,184 millionfrom$1,302 millionin2018, primarily due to alower composite wellhead naturalgas price ($280 million),partiallyoffset by an increase in natural gas deliveries($162 million). EOG'scomposite average wellhead naturalgas pricedecreased18% to $2.38 perMcf in 2019 compared to $2.92 perMcf in 2018. Naturalgas deliveries in 2019 increased 12% to 1,366 MMcfd as compared to 1,219 MMcfd in 2018.The increase in production was primarilydue to higherdeliveries in theUnited Statesresulting fromincreased production of associated natural gas from the Permian Basin andhighernatural gasvolumes in SouthTexas.

38 During 2019, EOG recognized net gains on themark-to-market of financialcommodityderivativecontracts of $180 million, which included netcash received for settlementsofcrude oil andnatural gas financial derivative contractsof$231 million. During 2018, EOGrecognized netlosses on the mark-to-market of financial commodity derivative contracts of $166 million, which includednet cash paid for settlementsofcrudeoil and natural gasfinancial derivative contractsof$259 million.

Gathering, processing andmarketing revenueslessmarketing costsin2019 decreased$18 million compared to 2018, primarily duetolower margins on crude oil andcondensatemarketing activities,partially offset by highermargins on natural gas marketingactivities.

Operating and OtherExpenses

2020 comparedto2019.During 2020, operating expenses of $11,576million were $2,105 millionlower thanthe $13,681 million incurred during 2019. The following table presents the costs per barrelofoil equivalent(Boe)for the years ended December 31, 2020 and2019: 2020 2019

Leaseand Well $3.85$ 4.58 Transportation Costs 2.66 2.54 Depreciation, Depletion andAmortization(DD&A) - Oil andGas Properties 11.85 12.25 Other Property,Plant and Equipment 0.47 0.31 Generaland Administrative (G&A) 1.75 1.64 NetInterest Expense 0.74 0.62 Total (1) $21.32 $21.94

(1)Total excludes gathering and processing costs, exploration costs, dry hole costs, impairments, marketingcosts and taxesother than income.

The primary factors impacting the cost components of per-unitrates of lease and well,transportation costs,DD&A, G&A and net interest expensefor 2020 compared to 2019 are set forth below. See"Operating Revenues andOther" above for a discussion of production volumes.

Lease andwell expenses include expenses for EOG-operated properties,aswellasexpensesbilledtoEOG from other operators where EOGisnot the operator of aproperty. Leaseand wellexpensescan be divided intothe following categories: coststooperateand maintaincrude oiland natural gaswells,the costofworkovers and lease andwelladministrative expenses. Operating and maintenancecostsinclude, among otherthings, pumping services, saltwaterdisposal, equipment repair and maintenance,compression expense,lease upkeepand fuel and power. Workoversare operations to restore or maintain production from existing wells.

Each of these categories of costsindividuallyfluctuatesfromtime to timeasEOG attemptstomaintainand increase production whilemaintaining efficient, safe andenvironmentally responsible operations. EOG continues to increase its operating activities by drilling new wells in existing and newareas. Operating and maintenancecosts withinthese existing and new areas, as wellasthe costsofservices charged to EOG by vendors, fluctuate over time.

Lease andwell expensesof$1,063 million in 2020 decreased $304 million from $1,367 million in 2019 primarily due to lower operating and maintenance costsinthe United States($157 million) and in Canada ($25 million),lower workovers expenditures in the UnitedStates ($103 million) and lower leaseand well administrativeexpensesinthe United States ($12 million). Leaseand well expenses decreased in the United Statesprimarily due to decreased operating activitiesresulting from decreased production, efficiency improvements andservice cost reductions.

Transportationcostsrepresentcosts associated withthe delivery of hydrocarbon productsfromthe leaseoran aggregation point on EOG's gatheringsystem to adownstream pointofsale. Transportationcostsinclude transportation fees, the cost of compression (the cost of compressing natural gastomeetpipelinepressure requirements), the cost of dehydration (the cost associated with removing water from natural gas to meet pipeline requirements), gathering fees andfuelcosts.

39 Transportationcosts of $735 millionin2020 decreased $23 million from $758 million in 2019 primarily due to decreased transportation costsinthe Fort WorthBasin ($27 million), the RockyMountainarea ($24 million) and the Eagle Ford ($20 million), partially offset by increasedtransportationcosts in thePermianBasin ($56 million).

DD&A of the cost of provedoil andgas properties is calculatedusing the unit-of-production method. EOG'sDD&A rate and expense are the compositeofnumerous individual DD&A group calculations. There are severalfactors thatcan impact EOG'scompositeDD&A rate and expense,suchasfield production profiles, drilling or acquisitionofnew wells, disposition of existing wells andreserve revisions (upward or downward) primarilyrelatedtowell performance,economic factorsand impairments. Changestothese factorsmay cause EOG'scompositeDD&A rate and expense to fluctuate from period to period.DD&A of the costofother property, plant and equipment is generally calculated usingthe straight-linedepreciation method overthe useful lives of the assets.

DD&A expenses in 2020 decreased$350millionto$3,400 millionfrom$3,750 million in 2019.DD&A expenses associated with oil and gasproperties in 2020 were $390 million lowerthanin2019primarily due to adecrease in production in theUnited States($222 million) and Trinidad($22million) and lowerunitrates in theUnited States($150 million). Unit rates in theUnited Statesdecreased primarilydue to upward reserve revisions and reserves addedatlower costsasaresultof increased efficiencies. DD&Aexpensesassociated withother property, plant and equipment in 2020 were $40 million higher thanin2019primarilydue to an increase in expense related to gathering and storageassets andequipment.

G&Aexpensesof$484 million in 2020 decreased$5million from $489 million in 2019 primarily due to decreased employee-related expenses($43 million) and professionaland otherservices($7 million), partially offset by idleequipment and termination fees ($46 million).

Net interest expenseof$205 million in 2020 was $20millionhigherthan2019primarily due to theissuance of the NotesinApril 2020 ($51 million) and lower capitalized interest ($7million),partially offset by repayment in June 2019 of the $900 million aggregate principal amount of 5.625% Senior Notesdue 2019 ($21 million), repayment in June 2020 of the$500 million aggregateprincipalamount of 4.40% Senior Notesdue 2020 ($13 million) andrepayment in April 2020 of the $500 million aggregate principalamount of 2.45% Senior Notes due 2020 ($10 million).

Gathering andprocessing costsrepresent operating andmaintenanceexpenses and administrativeexpensesassociated withoperating EOG's gathering and processing assets as well as natural gasprocessing fees andcertain NGLs fractionation fees paidtothird parties.EOG pays third partiestoprocess themajority of itsnatural gas production to extract NGLs.

Gathering and processing costs decreased$20 million to $459 millionin2020compared to $479 millionin2019 primarily due to decreasedoperating costsinthe EagleFord($16 million) and decreased gathering andprocessingfees in the Eagle Ford ($9 million) and the Fort Worth Basin Barnett Shale($5 million); partiallyoffset by increased gathering and processing fees in the Permian Basin ($15 million).

Exploration costsof$146 million in 2020 increased $6 million from $140 million in 2019 primarily duetoincreased geologicaland geophysicalexpendituresinthe United States($15million), partiallyoffset by decreased general and administrative expensesinthe UnitedStates ($8 million).

Impairmentsinclude: amortization of unproved oil andgas propertycosts as well as impairments of provedoil andgas properties;otherproperty, plant and equipment; and otherassets. Unproved properties with acquisition costs thatare not individuallysignificant areaggregated, and the portion of suchcostsestimated to be nonproductive is amortizedover the remaining lease term. Unprovedproperties withindividually significantacquisition costsare reviewedindividually for impairment.When circumstances indicatethataproved propertymay be impaired, EOG compares expected undiscounted future cash flows at aDD&A group level to the unamortizedcapitalized costofthe asset. If the expected undiscountedfuture cash flows, based on EOG's estimates of (and assumptions regarding) future crude oil, NGLs andnaturalgas prices, operating costs, development expenditures, anticipated production from proved reserves and other relevant data, are lowerthanthe unamortizedcapitalized cost,the capitalizedcost is reduced to fair value. Fair value is generally calculated by usingthe IncomeApproachdescribed in theFair ValueMeasurement Topic of the Financial Accounting Standards Board's Accounting Standards Codification(ASC). In certain instances, EOG utilizesacceptedoffersfromthird-party purchasers as thebasisfor determining fairvalue.

40 Thefollowing table representsimpairments forthe years ended December 31, 2020 and2019(in millions):

2020 2019

Proved properties $1,268 $207 Unproved properties 472 220 Otherassets 300 91 Firm commitmentcontracts 60 — Total $2,100 $518

Impairmentsofproved properties were primarily due to thewrite-down to fair value of legacy and non-core natural gasand crudeoil andcombo playsin2020 andlegacynatural gasassets in 2019.

Taxesother than income include severance/production taxes, ad valorem/propertytaxes, payroll taxes, franchise taxes andothermiscellaneoustaxes. Severance/production taxes aregenerally determined based on wellhead revenues, and ad valorem/property taxes are generally determined based on thevaluation of the underlying assets.

Taxes otherthanincomein2020 decreased $322 million to $478 million (6.6% of wellheadrevenues) from $800 million (6.9% of wellheadrevenues) in 2019. The decreaseintaxes other than income was primarilydue to decreased severance/production taxes in the United States($232 million), decreased ad valorem/propertytaxes in theUnited States ($51 million) andastate severancetax refund ($27 million).

Otherincome,net, was$10 million in 2020 comparedtoother income,net,of$31 millionin2019. Thedecrease of $21millionin2020 was primarilydue to adecreaseininterest income.

In response to the economicimpacts of the COVID-19 pandemic, the President of the United Statessignedthe Coronavirus Aid, Relief,and Economic Security Act (theCARES Act) into law on March 27, 2020. TheCARES Actprovides economic support to individuals and businesses through enhanced loanprograms, expanded unemployment benefits, andcertain payrolland incometax relief, among otherprovisions. Theprimary tax benefitofthe CARESAct for EOG was the acceleration of approximately $150 million of additional refundablealternative minimumtax (AMT) creditsintotax year 2019. These creditsoriginated from AMT paid by EOG in years prior to 2018 and were reflected as adeferred tax asset and anon- current receivable as of December31, 2019 sincetheyhad been expectedtoeither offset futurecurrent taxliabilities or be refundedonadeclining balance schedulethrough 2021. The$150 million of additional refundable AMTcreditswas received in July 2020.

Furtherpandemicreliefwas containedinthe ConsolidatedAppropriationsAct of 2021 (the CA Act) whichwas signed intolaw by the President of the United StatesonDecember27, 2020. In addition, the CA Actprovidedgovernment funding and limitedcorporate incometax relief primarily related to making permanent or extending certain tax provisions, none of whichwereamaterial benefitfor EOG.

EOG recognized an incometax benefit of $135 million in 2020 comparedtoanincome tax provision of $810 million in 2019, primarilydue to decreasedpretax income.The net effectivetax rate for 2020 decreased to 18% from 23%in2019. The lower effective tax rate is mostly duetotaxes attributable to EOG's foreignoperations andincreasedstock-based compensation tax deficiencies.

41 2019 comparedto2018.During 2019, operating expenses of $13,681 millionwere$875million higherthanthe $12,806 million incurredduring 2018. The following table presents the costsper Boe for the years endedDecember 31,2019 and 2018: 2019 2018

Leaseand Well $4.58$ 4.89 Transportation Costs 2.54 2.85 Depreciation, Depletion andAmortization(DD&A) - Oil andGas Properties 12.25 12.65 Other Property,Plantand Equipment 0.31 0.44 Generaland Administrative(G&A) 1.64 1.63 NetInterest Expense 0.62 0.93 Total (1) $21.94 $23.39

(1)Total excludes gathering and processing costs, exploration costs, dry hole costs, impairments, marketingcosts and taxesother than income.

The primary factors impacting the cost components of per-unitrates of lease and well,transportation costs,DD&A, G&A and net interest expensefor 2019 compared to 2018 are set forth below. See"Operating Revenues andOther" above for a discussion of production volumes.

Lease andwellexpenses of $1,367 millionin2019 increased $84 millionfrom$1,283 million in 2018 primarily dueto higheroperatingand maintenance costs($76 million) and higher leaseand well administrative expenses($29million) in the United States, partially offsetbylower operatingand maintenancecosts in the ($15 million) due to thesale of operations in the fourth quarter of 2018 and in Canada ($11 million). Leaseand well expensesincreased in the UnitedStates primarily duetoincreasedoperating activitiesresultinginincreased production.

Transportationcosts of $758 million in 2019 increased $11 million from $747 millionin2018primarilydue to increasedtransportation costsinthe Permian Basin($91million) andSouth Texas ($11 million),partially offset by decreased transportation costsinthe EagleFord ($77 million)and the Fort WorthBasin Barnett Shale ($13 million).

DD&A expenses in 2019 increased $315 million to $3,750 million from $3,435 million in 2018. DD&Aexpenses associated withoil andgas properties in 2019 were $337 million higherthan in 2018 primarily duetoanincrease in production in the United States($489 million),partially offset by lowerunitrates in theUnitedStates ($119million) and the sale of the United Kingdom operationsinthe fourth quarterof2018($33million). Unit rates in the United States decreased primarily due to upward reserve revisions andreserves addedatlower costsasaresultofincreasedefficiencies.

G&A expenses of $489 million in 2019 increased $62 million from $427 million in 2018 primarily due to increased employee-related expenses($48 million) and increased informationsystems costs ($8 million) resultingfromexpanded operations.

Net interest expense of $185 million in 2019 was$60 million lowerthan2018primarilydue to repayment of the $900 million aggregateprincipal amount of 5.625% Senior Notes due 2019 in June 2019 ($30 million) and the$350million aggregateprincipalamount of 6.875% Senior Notesdue 2018 in October2018 ($18 million) andanincrease in capitalized interest ($14 million).

Gathering and processing costsincreased $42 millionto$479millionin2019comparedto$437millionin2018 primarily duetoincreased operating costs and feesinthe Permian Basin($52million), the Rocky Mountain area($13 million) and SouthTexas ($5 million); partiallyoffsetbydecreased operating costsinthe United Kingdom ($33 million) due to thesale of operations in thefourth quarter of 2018.

Exploration costsof$140 million in 2019 decreased $9 million from $149 millionin2018primarily duetodecreased geologicaland geophysicalexpendituresinthe Trinidad($17million),partially offset by increased general andadministrative expensesinthe UnitedStates($7 million).

42 Thefollowing table representsimpairments forthe years ended December 31, 2019 and2018(in millions):

2019 2018

Proved properties $207 $121 Unproved properties 220 173 Otherassets 91 49 Inventories —4 Total $518 $347

Impairmentsofproved properties were primarily duetothe write-down to fair value of legacy natural gas assetsin 2019 and2018.

Taxes other than income in 2019 increased $28 million to $800 million (6.9% of wellhead revenues) from $772 million (6.5% of wellheadrevenues) in 2018. The increase in taxes otherthanincomewas primarily duetoanincreaseinad valorem/propertytaxes ($53 million), partially offset by an increase in creditsavailabletoEOG in 2019 forstate incentive severance tax rate reductions ($12 million) andadecrease in severance/productiontaxes ($12 million)primarily as aresultof decreased wellhead revenues, allinthe United States.

Otherincome,net,was $31 million in 2019 compared to otherincome, net,of$17 million in 2018. Theincreaseof $14 million in 2019 wasprimarilydue to an increase in interest income ($14 million) and an increaseinforeign currency transaction gains ($9million), partially offsetbyanincrease in deferredcompensation expense ($4 million).

EOG recognizedanincome taxprovision of $810 million in 2019 compared to an income tax provisionof$822 million in 2018, primarily due to decreased pretaxincome, partially offsetbythe absenceoftax benefits from certain taxreform measurement-period adjustments. Thenet effective tax rate for2019increased to 23%from19% in the prioryear, primarily duetothe absenceoftax benefitsfromcertaintax reform measurement-period adjustments.

Capital Resourcesand Liquidity

Cash Flow

The primary sourcesofcashfor EOG during the three-year period endedDecember 31,2020, were funds generated from operations, netproceedsfromthe issuance of long-term debt, net cash receivedfrom settlementsofcommodity derivative contracts andproceedsfromasset sales. Theprimary uses of cash were funds usedinoperations;exploration and development expenditures; repayments of debt;dividend paymentstostockholders and other property, plant andequipment expenditures.

2020 comparedto2019. Net cash providedbyoperating activitiesof$5,008 million in 2020 decreased$3,155 million from $8,163 million in 2019 primarily due to adecrease in wellhead revenues ($4,291million); unfavorable changes in working capitaland other assets and liabilities($166 million); adecreaseingathering,processing and marketing revenues less marketing costs($124 million)and an increase in net cash paid for income taxes($86million);partiallyoffset by an increaseincash received for settlementsofcommodity derivative contracts($840 million) and adecrease in cash operating expenses($641 million).

Net cash used in investing activities of $3,348 million in 2020 decreased by $2,829 millionfrom$6,177 million in 2019 primarily duetoadecrease in additions to oil andgas properties ($2,908 million); an increase in proceedsfromthe saleof assets ($52 million); adecreaseinadditions to other property, plant andequipment ($49 million);and adecrease in other investing activities($10 million); partiallyoffset by an unfavorable change in working capital associated withinvesting activities ($190million).

Net cash used in financing activities of $359 million in 2020 included repaymentsoflong-termdebt($1,000 million), cash dividend payments ($821 million), repayment of financelease liabilities ($19 million) and purchases of treasury stock in connection with stockcompensation plans ($16 million). Cash providedbyfinancingactivitiesin2020included long-term debt borrowings ($1,484 million) and proceeds from stockoptionsexercised andemployeestock purchase plan activity ($16 million).

43 2019 compared to 2018. Netcashprovidedbyoperating activities of $8,163 million in 2019 increased $394 million from $7,769 millionin2018 primarilyreflectinganincrease in cash received for settlementsofcommodity derivative contracts ($490 million), adecrease in net cash paidfor income taxes ($367million) and favorable changes in working capital andother assets andliabilities ($122 million);partially offset by adecrease in wellhead revenues ($365 million) and an increaseincash operating expenses($202 million).

Net cash usedininvesting activitiesof$6,177 million in 2019 increased by $7 million from $6,170 million in 2018 primarily duetoanincrease in additions to oiland gasproperties ($313 million), adecrease in proceeds from the sale of assets ($87 million) and an increase in additions to other property, plant and equipment ($33 million); partially offset by favorable changes in working capital associated withinvesting activities ($416million) and adecreaseinother investingactivities($10 million).

Net cash used in financingactivities of $1,513 million in 2019 includedrepayments of long-term debt ($900 million), cash dividend payments ($588 million)and purchases of treasury stockinconnection with stockcompensation plans ($25 million). Cash provided by financing activities in 2019 included proceedsfromstockoptions exercised and employeestock purchase planactivity($18 million).

Total Expenditures

The table belowsetsout components of total expenditures for the yearsended December31, 2020, 2019 and 2018 (in millions): 2020 2019 2018 Expenditure Category Capital Explorationand Development Drilling $2,664 $4,951 $4,935 Facilities 347 629 625 LeaseholdAcquisitions (1) 265 276 488 Property Acquisitions (2) 135 380 124 Capitalized Interest 31 38 24 Subtotal 3,442 6,274 6,196 Exploration Costs 146 140 149 Dry HoleCosts 13 28 5 Explorationand Development Expenditures 3,601 6,442 6,350 AssetRetirement Costs 117 186 70 Total Exploration andDevelopment Expenditures 3,718 6,628 6,420 Other Property, Plant andEquipment (3) 395 272 286 Total Expenditures $4,113 $6,900 $6,706

(1) Leasehold acquisitions included $197 million, $98 million and$291million related to non-cash property exchanges in 2020, 2019 and 2018, respectively. (2) Property acquisitions included$15 million, $52 million and $71 million relatedtonon-cash property exchanges in 2020, 2019and 2018, respectively. (3) Other property, plant and equipment included non-cash additions of $174million, primarily related to financelease transactions for storage facilities, and$49 million, primarily related to afinance lease transaction in thePermian Basin, in 2020 and2018, respectively.

44 Explorationand developmentexpendituresof$3,601 millionfor 2020 were $2,841 million lower thanthe prior year. The decreasewas primarily due to decreasedexploration anddevelopment drilling expendituresinthe United States ($2,309 million), decreased facilities expenditures($282 million) and decreasedproperty acquisitions ($245 million), partially offset by increasedexploration and developmentdrilling expenditures in Trinidad($27million). The 2020exploration and development expenditures of $3,601 million included $2,905 million in development drillingand facilities, $530 millioninexploration,$135 million in propertyacquisitions and$31 million in capitalized interest. The 2019 explorationand development expendituresof $6,442 million included$5,513 millionindevelopment drilling and facilities, $511 million in exploration, $380 million in property acquisitions and $38 million in capitalized interest.The 2018 exploration and developmentexpendituresof$6,350 million included$5,546 million in development drilling and facilities, $656 million in exploration, $124 million in property acquisitionsand $24 millionincapitalized interest.

The level of exploration and development expenditures, includingacquisitions, willvary in future periodsdepending on energy market conditions andothereconomic factors.EOG believesithas significantflexibilityand availability with respect to financing alternativesand the ability to adjust its exploration and developmentexpenditure budget as circumstances warrant. While EOG hascertaincontinuing commitments associated withexpenditure plans related to its operations, such commitmentsare not expected to be material when consideredinrelationtothe total financial capacity of EOG.

CommodityDerivative Transactions

Crude Oil Derivative Contracts. Prices receivedbyEOG forits crudeoil production generally vary from U.S. New York Mercantile Exchange (NYMEX) Intermediate (WTI)pricesdue to adjustmentsfor delivery location(basis) and other factors. EOG hasentered intocrude oilbasisswap contracts in order to fix the differentialbetween Intercontinental Exchange (ICE)Brent pricing and pricing in Cushing, Oklahoma(ICEBrent Differential). Presented below is acomprehensive summary of EOG's ICE Brent Differential basisswapcontracts through February 18,2021. Theweighted average price differential expressedin$/Bbl representsthe amount of addition to Cushing,Oklahoma,pricesfor the notional volumes expressed in Bbld coveredbythe basisswap contracts.

ICE BrentDifferential BasisSwap Contracts Weighted Average Price Volume Differential (Bbld) ($/Bbl) 2020 May2020 (closed) 10,000 $4.92

EOG has also enteredinto crude oil basis swap contractsinorder to fix the differential between pricing in Houston, Texas,and Cushing, Oklahoma (Houston Differential). Presentedbelow is acomprehensive summary of EOG's Houston Differentialbasis swap contractsthrough February 18, 2021. The weighted average price differentialexpressedin$/Bbl representsthe amount of additiontoCushing, Oklahoma, pricesfor the notionalvolumes expressed in Bbld covered by the basis swap contracts.

HoustonDifferential BasisSwap Contracts Weighted Average Price Volume Differential (Bbld) ($/Bbl) 2020 May2020 (closed) 10,000 $1.55

45 EOGhas also enteredinto crude oilswaps in order to fixthe differential in pricing betweenthe NYMEXcalendar monthaverage andthe physical crude oil deliverymonth(RollDifferential).Presented below is acomprehensive summary of EOG'sRollDifferential basis swapcontracts through February 18,2021. Theweightedaverage pricedifferentialexpressed in $/Bblrepresentsthe amount of netaddition (reduction)todelivery monthpricesfor the notionalvolumesexpressed in Bbld covered by the swapcontracts.

Roll Differential BasisSwap Contracts Weighted Average Price Volume Differential (Bbld) ($/Bbl) 2020 February 1, 2020 throughJune 30, 2020 (closed) 10,000 $0.70 July1,2020 through September30, 2020 (closed) 88,000 (1.16) October1,2020 through December31, 2020 (closed) 66,000 (1.16)

2021 February 2021 (closed) 30,000 $0.11 March 1, 2021 through December31, 2021 125,000 0.17

2022 January 1, 2022 through December31, 2022 125,000 $0.15

In May 2020, EOG enteredinto crude oilRollDifferential basis swap contractsfor the period from July 1, 2020 through September 30, 2020, withnotional volumes of 22,000 Bbldataweighted average pricedifferential of $(0.43) per Bbl, and for the period from October 1, 2020 through December 31,2020, withnotional volumes of 44,000 Bbldataweighted average pricedifferential of $(0.73) per Bbl.These contracts partially offset certain outstandingRollDifferential basisswap contracts forthe sametimeperiods and volumesataweighted average pricedifferentialof$(1.16) per Bbl. EOG paidnet cash of $3.2 million for the settlement of these contracts. Theoffsetting contracts were excluded from the above table.

Presentedbelow is acomprehensive summary of EOG's crudeoil NYMEX WTI price swap contracts through February 18, 2021, withnotionalvolumes expressedinBbldand pricesexpressed in $/Bbl.

CrudeOil NYMEX WTI PriceSwap Contracts Weighted Volume Average Price (Bbld) ($/Bbl) 2020 January 1, 2020 through March 31, 2020 (closed) 200,000 $59.33 April 1, 2020 through May31, 2020 (closed) 265,000 51.36

2021 January 2021 (closed) 151,000 $50.06 February 1, 2021 through March31, 2021 201,000 51.29 April 1, 2021 through June 30, 2021 150,000 51.68 July1,2021 through September 30, 2021 150,000 52.71

46 In April andMay 2020, EOG entered intocrude oil NYMEXWTI priceswapcontracts forthe period from June1, 2020 through June 30, 2020, withnotionalvolumes of 265,000 Bbld at aweighted average priceof$33.80 per Bbl, for the period from July1,2020 through July 31, 2020, withnotionalvolumes of 254,000 Bbldataweighted average priceof$33.75 per Bbl, for the period from August 1, 2020 through September 30, 2020, with notionalvolumes of 154,000 Bbld at aweighted average priceof$34.18 per Bbland for the periodfromOctober 1, 2020 through December 31, 2020, withnotional volumesof 47,000 Bbldataweighted average priceof$30.04 per Bbl.These contracts offsetthe remainingcrude oil NYMEXWTI price swap contractsfor the sametimeperiods and volumesataweighted average priceof$51.36per Bbl for the periodfromJune 1, 2020 through June 30,2020, $42.36 per Bblfor the period from July1,2020through July31, 2020, $50.42 per Bbl for the period from August 1, 2020 through September 30,2020and $31.00 per Bbl for the periodfromOctober 1, 2020 through December 31, 2020. EOGreceivednet cash of $364.0 million forthe settlement of these contracts. The offsetting contracts were excluded from the above table.

Presentedbelow is acomprehensive summary of EOG'scrude oil ICE Brent price swap contractsthrough February 18, 2021, withnotional volumes expressedinBbldand prices expressedin$/Bbl.

Crude OilICE BrentPrice Swap Contracts Weighted Volume Average Price (Bbld) ($/Bbl) 2020 April 2020 (closed) 75,000 $25.66 May2020 (closed) 35,000 26.53

NGLs Derivative Contracts. Presented below is acomprehensive summary of EOG's Mont Belvieu propane (non- TET) price swapcontractsthrough February 18, 2021, with notional volumesexpressedinBbldand prices expressedin$/Bbl.

MontBelvieu Propane PriceSwap Contracts Weighted Volume Average Price (Bbld) ($/Bbl) 2020 January 1, 2020 through February 29, 2020 (closed) 4,000 $21.34 March1,2020 through April 30, 2020 (closed) 25,000 17.92

2021 January 2021 (closed) 15,000 $29.44 February 1, 2021 through December31, 2021 15,000 29.44

In April andMay 2020, EOG enteredintoMont Belvieu propane priceswapcontracts for the period from May 1, 2020 through December31, 2020, withnotionalvolumesof25,000 Bbldataweighted average priceof$16.41 perBbl. These contracts offset the remaining Mont Belvieupropane priceswapcontracts for the same time period withnotionalvolumes of 25,000 Bbldataweightedaverage priceof$17.92per Bbl.EOG received netcashof$9.2 million forthe settlement of these contracts. The offsetting contractswereexcludedfrom the above table.

47 NaturalGas Derivative Contracts. Presentedbelow is acomprehensive summary of EOG's naturalgas NYMEX Henry Hub priceswapcontractsthrough February 18, 2021, withnotionalvolumes sold (purchased) expressedinmillion British thermalunits(MMBtu) per day (MMBtud) andpricesexpressedindollars per MMBtu($/MMBtu). In January 2021, EOG executed the early terminationprovision granting EOG the right to terminate certain 2022 natural gasNYMEX Henry Hub priceswap contractswithnotional volumesof20,000 MMBtud at aweighted average price of $2.75 per MMBtu forthe period from January1,2022 through December31, 2022. EOGreceivednet cash of $0.6 million for the settlement of these contracts.

Natural GasNYMEX HenryHub Price Swap Contracts Weighted Volume Average Price (MMBtud) ($/MMBtu) 2021 April 1, 2021 through September 30, 2021 (70,000) $2.64

2022 January 1, 2022 through December31, 2022 (closed) 20,000 $2.75

In December2020 and January 2021, EOG enteredinto natural gasNYMEXHenry Hub price swap contracts for the period from January 1, 2021 through March31, 2021, withnotional volumes of 500,000 MMBtud at aweighted average price of $2.43 per MMBtu and for the period from April 1, 2021 through December 31, 2021, withnotional volumes of 500,000 MMBtud at aweighted average price of $2.83 per MMBtu. Thesecontracts offsetthe remaining naturalgas NYMEXHenry Hub priceswapcontracts for the sametimeperiods with notionalvolumes of 500,000 MMBtud at aweightedaverage priceof $2.99 per MMBtu. EOG received net cashof$16.5 million through February 18, 2021, for the settlementofcertain of these contracts, and expectstoreceive net cash of $30.3 million during the remainder of 2021 for the settlement of the remaining contracts. The offsettingcontractswere excluded from the above table.

Presentedbelow is acomprehensive summary of EOG'snatural gasJapanKorea Marker (JKM) price swap contracts through February 18, 2021, with notional volumesexpressedinMMBtudand prices expressedin$/MMBtu.

Natural GasJKM PriceSwapContracts Weighted Volume Average Price (MMBtud) ($/MMBtu) 2021 April 1, 2021 through September 30, 2021 70,000 $6.65

48 EOGhas enteredinto natural gas collarcontracts, which establish ceiling andfloorpricesfor the saleofnotional volumes of natural gasasspecifiedinthe collar contracts. Thecollars require that EOG paythe difference between the ceiling priceand the Henry HubIndex Priceinthe event the HenryHub Index Price is above the ceilingprice.The collarsgrant EOG the right to receive thedifferencebetween the floorprice and the HenryHub Index Price in theevent the Henry Hub Index Priceisbelowthe floorprice.InMarch 2020, EOG executed the early terminationprovision granting EOG the right to terminate certain 2020 natural gas collar contractswithnotional volumesof250,000 MMBtud at aweighted average ceiling price of $2.50 per MMBtuand aweightedaverage floor price of $2.00 per MMBtu for the period from April 1, 2020 through July 31, 2020. EOGreceived net cash of $7.8 million for the settlement of these contracts. Presentedbelow is a comprehensive summary of EOG's natural gascollar contracts through February 18, 2021, withnotional volumes expressedin MMBtud andpricesexpressed in $/MMBtu.

Natural GasCollar Contracts WeightedAverage Price ($/MMBtu) Volume (MMBtud) CeilingPrice FloorPrice 2020 April 1, 2020 through July31, 2020 (closed) 250,000 $2.50 $2.00

In April2020, EOG enteredinto natural gascollar contracts for the period from August 1, 2020 through October31, 2020, withnotionalvolumes of 250,000 MMBtud at aceilingprice of $2.50 per MMBtuand afloor priceof$2.00 per MMBtu. These contractsoffset theremaining naturalgas collar contracts forthe sametimeperiod withnotional volumes of 250,000 MMBtud at aceilingprice of $2.50 per MMBtu and afloor priceof$2.00 perMMBtu. EOGreceived net cash of $1.1 million for the settlement of thesecontracts. Theoffsettingcontractswereexcludedfrom the above table.

Pricesreceived by EOG for its natural gasproduction generally vary from NYMEXHenry Hubpricesdue to adjustmentsfor delivery location (basis) and otherfactors. EOGhas enteredintonatural gasbasis swap contracts in order to fixthe differentialbetweenpricing in theRocky Mountain areaand NYMEXHenry Hub prices(RockiesDifferential). Presentedbelow is acomprehensive summary of EOG's Rockies Differentialbasisswapcontracts through February 18, 2021. The weighted average pricedifferential expressedin$/MMBtu represents theamount of reduction to NYMEXHenry Hub prices for the notional volumes expressedinMMBtud coveredbythe basisswapcontracts.

RockiesDifferential BasisSwap Contracts Weighted Average Price Volume Differential (MMBtud) ($/MMBtu) 2020 January 1, 2020 through December 31, 2020 (closed) 30,000 $0.55

49 EOGhas also entered into natural gasbasis swapcontracts in order to fixthe differentialbetween pricing at the Houston ShipChannel(HSC) and NYMEXHenry Hub prices (HSC Differential).InMarch 2020, EOG executed the early termination provision granting EOG the right to terminate certain 2020 HSC Differentialbasis swaps withnotional volumesof 60,000 MMBtud at aweightedaverage pricedifferential of $0.05per MMBtu for the period from April 1, 2020 through December 31, 2020. EOGpaid net cashof$0.4 million for the settlementofthese contracts. Presented below is a comprehensive summary of EOG's HSC Differentialbasis swap contracts through February 18, 2021. The weighted average pricedifferentialexpressed in $/MMBtu represents the amount of reductiontoNYMEX Henry Hub pricesfor the notional volumes expressedinMMBtud covered by thebasisswap contracts.

HSCDifferential Basis Swap Contracts Weighted Average Price Volume Differential (MMBtud) ($/MMBtu) 2020 January 1, 2020 through December 31, 2020 (closed) 60,000 $0.05

EOG hasalso enteredinto naturalgas basisswapcontracts in order to fix the differentialbetween pricing at the Waha Hub in WestTexas and NYMEXHenry Hubprices(WahaDifferential).Presentedbelowisacomprehensive summary of EOG'sWahaDifferential basis swap contracts throughFebruary 18, 2021. The weighted average pricedifferential expressed in $/MMBturepresentsthe amount of reduction to NYMEXHenry Hub pricesfor the notionalvolumes expressed in MMBtud covered by the basisswapcontracts.

Waha Differential BasisSwap Contracts Weighted Average Price Volume Differential (MMBtud) ($/MMBtu) 2020 January 1, 2020 through April30, 2020 (closed) 50,000 $1.40

In April 2020, EOG entered intoWahaDifferentialbasis swap contracts forthe periodfromMay 1, 2020 through December 31, 2020, withnotional volumesof50,000 MMBtud at aweighted averagepricedifferentialof$0.43 per MMBtu. These contracts offset theremaining WahaDifferential basis swap contracts forthe sametimeperiodwithnotional volumesof 50,000 MMBtud at aweightedaverage pricedifferentialof$1.40 per MMBtu. EOG paidnet cash of $11.9 million forthe settlementofthese contracts. The offsettingcontractswereexcludedfromthe abovetable.

Financing

EOG'sdebt-to-totalcapitalizationratio was22% at December31, 2020, compared to 19% at December 31, 2019.As used in this calculation, total capitalizationrepresentsthe sum of total current and long-term debt and total stockholders' equity.

At December 31, 2020 and2019, respectively, EOG hadoutstanding $5,640 million and $5,140 million aggregate principalamount of senior noteswhichhad estimated fair valuesof$6,505 million and$5,452 million, respectively. The estimated fair value of debt wasbased upon quotedmarketprices and, where such prices were not available, otherobservable inputsregarding interest rates availabletoEOG at year-end.EOG's debt is at fixed interest rates.While changes in interest rates affectthe fair valueofEOG's senior notes, suchchanges do not expose EOGtomaterial fluctuationsinearnings or cash flow.

During 2020, EOG fundedits capitalprogram andoperations primarily by utilizingcashprovidedbyoperating activities,issuanceofthe Notesand proceeds from assetsales. WhileEOG maintainsa$2.0billionrevolving credit facility to back its commercial paper program, there were no borrowings outstanding at any timeduring 2020 and the amount outstanding at year-end waszero. EOGconsiders the availability of its $2.0 billionsenior unsecured revolving credit facility,asdescribed in Note 2toConsolidatedFinancialStatements, to be sufficient to meet itsongoing operating needs.

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51 Contractual Obligations

The following table summarizes EOG'scontractualobligations at December 31, 2020 (in millions): 2026 & Contractual Obligations (1) Total 2021 2022-2023 2024-2025 Beyond

Current andLong-Term Debt $5,640 $750 $1,250 $500 $3,140 Interest PaymentsonLong-Term Debt 2,297 207 366 309 1,415 (2) Finance Leases 239 36 60 56 87 (2) OperatingLeases 1,039 323 344 166 206 (2) Leases Effective, Not Commenced 100 14 28 22 36 Transportation andStorage Service Commitments (3) 6,665 964 1,830 1,296 2,575 Purchase andServiceObligations 1,258 429 497 143 189 Total Contractual Obligations$17,238 $2,723 $4,375 $2,492 $7,648

(1) Thistable does not include the liability for unrecognized tax benefits, EOG's pensionorpostretirement benefit obligations or liability for dismantlement, abandonment and asset retirement obligations (see Notes6,7and 15,respectively, to Consolidated Financial Statements). These amounts are excluded because theyare subject to estimates and the timing of settlement is unknown. (2) For more information on contracts that meetthe definition of alease under ASU 2016-02, see Note 18 to Consolidated Financial Statements. (3) Amounts exclude transportation andstorage service commitments that meetthe definition of alease. Amounts shown are based on current transportationand storage rates and the foreign currency exchange rates used to convert Canadiandollars into UnitedStates dollars at December31, 2020. Managementdoes not believe that any future changes in theserates before the expiration dates of these commitments will have amaterialadverseeffectonthe financial conditionorresults of operationsofEOG.

Off-Balance Sheet Arrangements

EOG does not participateinfinancialtransactions thatgenerate relationships withunconsolidated entities or financial partnerships. Such entities or partnerships, oftenreferred to as variable interest entities (VIE)orspecial purposeentities (SPE), are generally established forthe purpose of facilitatingoff-balancesheet arrangementsorotherlimited purposes. EOGwas not involvedinany unconsolidated VIE or SPE financial transactionsorany other"off-balance sheet arrangement"(as defined in Item 303(a)(4)(ii) of Regulation S-K) during any of the periods coveredbythisreport andcurrentlyhas no intention of participating in any suchtransaction or arrangementinthe foreseeablefuture.

Foreign Currency Exchange RateRisk

During 2020, EOG was exposed to foreign currencyexchange rateriskinherent in its operations in foreign countries, including Trinidad, China andCanada. EOG continues to monitor the foreign currencyexchange rates of countriesinwhich it is currently conducting business andmay implement measures to protect against foreign currency exchangeraterisk.

52 Outlook

Pricing. Crude oil, NGLs andnatural gaspriceshave been volatile, and thisvolatilityisexpectedtocontinue. As a resultofthe many uncertainties associated withthe world political environment,worldwide supplies of, and demand for, crude oil and condensate, NGLs and natural gas,the availabilitiesofotherworldwide energy supplies and the relative competitive relationships of the various energy sources in the viewofconsumers, EOG is unabletopredict what changes mayoccur in crude oiland condensate,NGLs, natural gas,ammonia and methanol prices in the future.The marketprice of crude oil and condensate, NGLs and natural gasin2021 will impact theamountofcash generated from EOG'soperating activities,which willinturn impactEOG's financial position. As of February 18, 2021, the average 2021 NYMEXcrude oiland naturalgas priceswere$57.51per barreland $2.98 per MMBtu, respectively, representing an increase of 46% for crude oil andanincrease of 43% for natural gas from the average NYMEXpricesin2020. SeeITEM1A, Risk Factors.

Including the impactofEOG's crude oil andNGL derivativecontracts (exclusive of basisswaps) andbasedonEOG's taxposition,EOG's price sensitivity in 2021 foreach $1.00 per barrelincrease or decrease in wellheadcrude oiland condensate price, combinedwiththe estimatedchange in NGL price, is approximately $99 million for netincome and$127 million for pretax cash flows from operatingactivities.Including the impact of EOG'snatural gasderivativecontracts and based on EOG's taxposition andthe portion of EOG'santicipated naturalgas volumes for 2021 for which priceshave notbeendeterminedunder long-term marketingcontracts, EOG's pricesensitivity foreach$0.10 perMcf increase or decrease in wellhead naturalgas price is approximately $31 million for net incomeand $40million for pretax cash flows from operating activities.For information regarding EOG's crude oil,NGLsand natural gas financial commodityderivativecontracts through February 18, 2021, see "Commodity Derivative Transactions" above.

Capital. EOG plans to continuetofocus asubstantial portion of itsexplorationand development expendituresinits major producing areasinthe United States. In particular, EOG willbefocusedonUnited States crude oildrilling activity in its Delaware Basin,Eagle Fordand Rocky Mountain areawhere it generatesits highest rates-of-return. To furtherenhance the economics of these plays, EOG expectstocontinue to improve well performance and lower drilling andcompletion costs through efficiencygains and lowerservicecosts. In addition, EOG expects to spend aportionofits anticipated 2021 capital expenditures on leasingacreage andevaluatingnew prospects.

The totalanticipated 2021 capitalexpenditures of approximately$3.7billion to $4.1 billion, excluding acquisitions and non-cash transactions, is structured to maintain EOG'sstrategyofcapital discipline by funding its exploration, development and exploitation activities primarily from available internally generatedcashflows andcashonhand. EOGhas significant flexibility with respect to financing alternatives, includingborrowingsunder itscommercialpaper program,bank borrowings, borrowings under its $2.0 billion senior unsecured revolving credit facility andequityand debt offerings.

Operations. In 2021, total crude oil production is expected to remain at fourth quarter 2020 levels. In 2021, EOG expectstocontinue to focusonreducingoperating coststhrough efficiency improvements.

53 Summary of Critical Accounting Policies

EOG preparesits financialstatements and theaccompanyingnotesinconformity withaccounting principles generally accepted in theUnited States, whichrequire management to make estimates and assumptions about future events thataffect the reportedamounts in the financialstatementsand the accompanying notes. EOGidentifies certain accounting policies as critical basedon, among otherthings, their impact on EOG's financial condition, results of operations or liquidity, andthe degreeof difficulty, subjectivityand complexityintheir application. Critical accounting policies coveraccounting matters thatare inherently uncertain because the future resolution of suchmattersisunknown.Managementroutinely discussesthe development, selection anddisclosure of each of the critical accounting policies.Following is adiscussion of EOG's most criticalaccounting policies:

Proved Oiland Gas Reserves

EOG'sengineers estimateprovedoil andgas reserves in accordance with United StatesSecurities and Exchange Commission (SEC) regulations, which directly impactfinancial accounting estimates,including depreciation, depletionand amortizationand impairments of proved properties and related assets. Proved reservesrepresent estimatedquantities of crude oil andcondensate, NGLs and natural gas that geologicaland engineering datademonstrate,withreasonable certainty, to be recoverable in future yearsfromknown reservoirs under economicand operating conditions existing at the time theestimates weremade. The process of estimating quantitiesofprovedoil and gasreservesiscomplex, requiring significant subjective decisions in theevaluation of available geological,engineering and economic data foreachreservoir.The data for agiven reservoir mayalso change substantially over time as aresult of numerous factors including, but not limited to,additional development activity,evolving production history and continualreassessmentofthe viabilityofproduction undervarying economic conditions. Consequently, materialrevisions (upward or downward) to existing reserve estimates may occurfrom time to time.For related discussion, see ITEM 1A, Risk Factors, and "Supplemental InformationtoConsolidatedFinancial Statements."

Oil and Gas Exploration and Development Costs

EOGaccountsfor itscrude oiland naturalgas exploration and production activitiesunder the successful efforts method of accounting. Oiland gas exploration costs, otherthanthe costs of drilling exploratory wells, are expensed as incurred. Thecosts of drilling exploratory wells are capitalizedpendingdetermination of whetherEOG has discovered commercial quantities of proved reserves. If commercial quantities of provedreserves are notdiscovered, suchdrilling costs areexpensed. In some circumstances, it maybeuncertain whethercommercial quantities of proved reserves have been discoveredwhen drilling has been completed. Suchexploratory well drilling costsmay continuetobecapitalized if the estimated reservequantity is sufficient to justify itscompletion as aproducing welland sufficient progress in assessing the reserves and the economicand operating viability of the projectisbeing made.Coststodevelop proved reserves, including the costsofall development wells andrelated equipment used in theproduction of crude oil and natural gas, arecapitalized.

Depreciation, Depletion and Amortization for Oiland Gas Properties

The quantities of estimated provedoil andgas reservesare asignificant component of EOG'scalculation of depreciation, depletion and amortizationexpense, andrevisions in such estimates mayalter therate of future expense. Holding all otherfactors constant, if reservesare revisedupward or downward, earnings willincrease or decrease,respectively.

Depreciation, depletionand amortizationofthe cost of proved oil andgas properties is calculated usingthe unit-of- production method. Thereserve base used to calculate depreciation, depletionand amortizationfor leaseholdacquisition costs and the cost to acquire proved properties is the sum of proveddeveloped reservesand proved undevelopedreserves. With respect to leaseand wellequipment costs, which include development costsand successful exploration drilling costs, the reservebase includesonly proved developed reserves. Estimatedfuturedismantlement, restoration and abandonment costs, net of salvage values, aretaken into account.

Oiland gaspropertiesare groupedinaccordancewiththe provisions of the Extractive Industries-Oil andGas Topic of the ASC. Thebasisfor grouping is areasonableaggregation of propertieswithacommon geologicalstructural feature or stratigraphiccondition, suchasareservoirorfield.

Depreciation, depletion andamortization rates are updated quarterlytoreflectthe addition of capital costs, reserve revisions (upwards or downwards) andadditions, property acquisitions and/or property dispositions and impairments.

54 Depreciation andamortization of otherproperty, plant andequipment is calculatedonastraight-line basisover the estimated useful lifeofthe asset.

Impairments

Oil andgas lease acquisition costs are capitalized when incurred. Unproved properties withacquisitioncosts that are notindividuallysignificant areaggregated, and the portion of suchcostsestimated to be nonproductiveisamortized over the remaining lease term. Unproved properties withindividually significant acquisitioncostsare reviewed individuallyfor impairment. If theunproved propertiesare determined to be productive, theappropriate related costs are transferred to proved oiland gasproperties.Lease rentalsare expensed as incurred.

Whencircumstances indicatethatprovedoil and gaspropertiesmay be impaired,EOG compares expected undiscounted future cash flowsatadepreciation,depletion and amortizationgroup level to the unamortized capitalized cost of the asset.Ifthe expected undiscounted future cash flows, based on EOG'sestimates of (and assumptionsregarding) future crude oiland natural gas prices,operating costs, development expenditures, anticipatedproduction from provedreserves and otherrelevant data,are lowerthanthe unamortizedcapitalized cost, the capitalized costisreduced to fairvalue. Fair valueis generallycalculatedusing the IncomeApproach describedinthe Fair ValueMeasurement Topicofthe ASC. In certain instances, EOG utilizes acceptedoffersfromthird-party purchasers as the basisfor determining fairvalue. Estimatesof undiscountedfuture cash flows require significantjudgment, and the assumptions used in preparing suchestimates are inherently uncertain. In addition, suchassumptions and estimatesare reasonably likelytochange in the future.

Crude oil, NGLs and naturalgas prices have exhibited significantvolatility in the past,and EOGexpectsthatvolatility to continue in the future.During the five years endedDecember 31,2020, WTI crude oilspot priceshave fluctuated from approximately $(36.98) perbarrel to $77.41 per barrel, and Henry Hub naturalgas spot prices have ranged from approximately $1.33 perMMBtu to $6.24 per MMBtu. Market prices for NGLs are influencedbythe components extracted,including ethane, propane,butane andnaturalgasoline,among others, and the respective market pricing for each component.

EOG usesthe five-year NYMEXfuturesstrip forWTI crude oiland Henry Hub natural gasand the five-year Oil Price Information Servicesfutures stripfor NGLscomponents (in each case as of the applicable balance sheetdate) as abasisto estimate futurecrude oil,NGLsand natural gas prices. EOG'sprovedreserves estimates, includingthe timing of future production, are alsosubject to significantassumptions and judgment, and are frequentlyrevised (upwards anddownwards) as more information becomes available. Proved reservesare estimatedusing atrailing12-month averageprice,inaccordancewith SECrules. In the future,ifany combination of crude oilprices, NGLs prices, natural gasprices, actualproduction or operating costsdiverge negatively from EOG's current estimates,impairment charges and downward adjustments to our estimated proved reserves may be necessary.

Income Taxes

Incometaxesare accountedfor using the asset and liabilityapproach. Underthis approach, deferred taxassets and liabilitiesare recognized basedonanticipatedfuturetax consequences attributable to differencesbetweenfinancial statement carrying amountsofassets and liabilitiesand their respective tax basis. EOGassesses the realizability of deferred taxassets and recognizes valuation allowances as appropriate. Significant assumptionsused in estimating future taxableincome include future crude oil, NGLs and naturalgas pricesand levels of capital reinvestment. Changesinsuchassumptions or changes in tax laws andregulationscouldmaterially affect the recognized amounts of valuation allowances.

Stock-BasedCompensation

In accounting for stock-basedcompensation, judgmentsand estimates are made regarding, among otherthings, the appropriatevaluationmethodology to follow in valuing stockcompensation awards and the related inputs required by those valuation methodologies. Assumptions regarding expected volatility of EOG's common stock, the level of risk-freeinterest rates, expected dividend yields on EOG's common stock, the expectedterm of the awards, expected volatility in thepriceof sharesand composition of EOG's peercompanies and other valuation inputsare subjecttochange.Any such changescould resultindifferent valuations and thus impactthe amount of stock-basedcompensation expense recognized on the Consolidated Statements of Incomeand Comprehensive Income.

55 Information Regarding Forward-Looking Statements

This Annual Report on Form 10-K includesforward-looking statements within the meaning of Section 27Aofthe SecuritiesAct of 1933, as amended, andSection 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts,including, among others, statements and projections regarding EOG's future financial position,operations, performance,business strategy, goals, returns andratesofreturn, budgets, reserves, levels of production, capitalexpenditures, costs and assetsales, statements regarding future commoditypricesand statementsregarding the plans and objectives of EOG'smanagementfor futureoperations, are forward-looking statements. EOGtypically uses words such as "expect," "anticipate,""estimate,""project," "strategy," "intend,“ "plan," "target," "aims," "goal," "may," "will," "focusedon," "should" and "believe" or the negative of those terms or other variations or comparableterminologytoidentify its forward- looking statements. In particular, statements, express or implied, concerning EOG's futureoperatingresults and returns or EOG'sability to replaceorincrease reserves, increase production,generatereturns and ratesofreturn, replace or increase drilling locations, reduce or otherwise control operating costsand capitalexpenditures, generate cash flows,pay down or refinanceindebtedness, or payand/or increase dividends areforward-looking statements. Forward-looking statementsare not guarantees of performance. Although EOG believesthe expectations reflectedinits forward-lookingstatements arereasonable and are based on reasonable assumptions, no assurance canbegiven that these assumptions are accurate or thatany of these expectationswill be achieved (in full or at all) or willprove to have been correct.Moreover, EOG'sforward-looking statements maybeaffected by known, unknown or currently unforeseen risks, events or circumstances thatmay be outsideEOG's control. Importantfactorsthat could cause EOG's actualresults to differ materiallyfromthe expectationsreflectedinEOG's forward- looking statements include, among others:

•the timing, extent andduration of changes in prices for, supplies of, and demandfor,crude oiland condensate, natural gasliquids, natural gas andrelated commodities; •the extenttowhichEOG is successful in its effortstoacquire or discoveradditional reserves; •the extenttowhich EOG is successful in its effortsto(i) economically develop its acreage in,(ii)produce reserves and achieve anticipated production levelsand rates of return from,(iii) decrease or otherwise control its drilling, completion, operating and capital costsrelated to,and (iv) maximizereserverecovery from,its existingand future crude oiland natural gasexploration and development projectsand associatedpotentialand existing drilling locations; •the extent to whichEOG is successfulinits effortstomarketits production of crude oiland condensate,natural gas liquids, and naturalgas; •security threats, including cybersecuritythreats and disruptions to our business and operations from breaches of our information technology systems, physicalbreachesofour facilities andother infrastructure or breaches of the informationtechnology systems, facilitiesand infrastructure of third partieswith which we transactbusiness; •the availability,proximity and capacity of, and costsassociatedwith, appropriate gathering,processing, compression, storage, transportation, refining, and export facilities; •the availability,cost,terms and timing of issuance or execution of, and competition for, mineral licensesand leasesand governmentaland otherpermits and rights-of-way, and EOG's abilitytoretainmineral licenses and leases; •the impact of, and changesin, government policies,lawsand regulations, including any changes or otheractions whichmay resultfromthe recentU.S.electionsand change in U.S. administrationand includingtax laws and regulations; climate change and otherenvironmental, healthand safety laws andregulations relating to air emissions, disposalofproducedwater, drillingfluids and otherwastes,hydraulic fracturing and access to and use of water; laws and regulations affecting the leasing of acreage andpermitting foroil andgas drilling and the calculationofroyalty paymentsinrespect of oil andgas production; laws and regulations imposing additional permitting and disclosure requirements,additional operatingrestrictions andconditions or restrictions on drilling and completion operations and on the transportation of crude oiland naturalgas;lawsand regulationswithrespect to derivativesand hedging activities;and laws and regulations withrespecttothe importand export of crude oil, natural gas andrelated commodities; •EOG's ability to effectively integrate acquired crude oil and natural gas properties intoits operations, fullyidentify existing andpotential problemswith respecttosuchproperties and accuratelyestimatereserves, production and drilling, completing andoperatingcosts with respecttosuchproperties; •the extent to whichEOG's third-party-operatedcrude oiland natural gaspropertiesare operated successfully and economically; •competition in the oiland gas exploration and production industry for the acquisition of licenses, leasesand properties,employeesand other personnel, facilities, equipment, materialsand services; •the availability andcost of employees and other personnel,facilities, equipment, materials(such as waterand tubulars) and services; •the accuracy of reserveestimates, whichbytheirnature involve theexercise of professional judgmentand may therefore be imprecise;

56 •weather,including itsimpact on crudeoil andnatural gasdemand, and weather-related delaysindrilling and in theinstallation and operation(by EOGorthird parties) of production, gathering, processing, refining, compression, storage,transportation, and export facilities; •the ability of EOG's customers and othercontractual counterparties to satisfytheirobligations to EOG and, related thereto, to accessthe creditand capitalmarkets to obtain financing neededtosatisfy their obligations to EOG; •EOG's abilitytoaccessthe commercial paper marketand othercredit and capital marketstoobtain financingon termsitdeems acceptable,ifatall,and to otherwise satisfy itscapital expenditurerequirements; •the extenttowhichEOG is successfulinits completion of plannedassetdispositions; •the extentand effect of any hedging activities engaged in by EOG; •the timingand extentofchanges in foreign currencyexchange rates, interestrates,inflation rates,globaland domesticfinancialmarketconditions and globaland domestic generaleconomic conditions; •the durationand economic and financial impact of epidemics,pandemicsorother publichealthissues, including theCOVID-19 pandemic; •geopolitical factors and political conditions anddevelopments around the world (such as theimposition of tariffs or trade or other economicsanctions, political instability and armed conflict), including in the areas in which EOG operates; •the useofcompeting energy sourcesand the developmentofalternative energysources; •the extent to whichEOG incursuninsured lossesand liabilitiesorlossesand liabilitiesinexcess of itsinsurance coverage; •acts of warand terrorism and responsestothese acts; and •the other factors described under ITEM 1A, Risk Factors of thisAnnualReport on Form 10-K and any updates to thosefactors setforth in EOG's subsequent QuarterlyReports on Form 10-Q or CurrentReports on Form 8-K.

In light of these risks,uncertaintiesand assumptions, the events anticipated by EOG'sforward-looking statements may not occur, and, if any of such events do,wemay not have anticipated the timingoftheiroccurrence or the duration or extent of their impactonour actual results. Accordingly, you shouldnot place anyundue relianceonany of EOG's forward-looking statements. EOG's forward-looking statements speakonlyasofthe date made,and EOGundertakes no obligation, other thanas required by applicablelaw,toupdateorrevise its forward-looking statements, whetherasaresult of newinformation, subsequent events, anticipated or unanticipatedcircumstancesorotherwise.

ITEM7A. Quantitative andQualitativeDisclosures About Market Risk

The information required by thisItemisincorporated by referencefromItem7ofthis report,specifically the informationset forthunder the captions "Commodity DerivativeTransactions," "Financing," "Foreign CurrencyExchange Rate Risk" and "Outlook" in "Management's Discussion andAnalysisofFinancial Condition and ResultsofOperations -Capital Resources andLiquidity."

ITEM8. FinancialStatements and Supplementary Data

The information required by thisItemisincluded in this report as setforthinthe "Index to Financial Statements" on page F-1 andisincorporated by reference herein.

ITEM9. Changes in and Disagreements withAccountants on Accounting and Financial Disclosure

None.

ITEM9A. Controlsand Procedures

Disclosure Controls andProcedures. EOG's management, withthe participationofEOG's principalexecutive officer and principalfinancial officer,evaluated theeffectiveness of EOG's disclosure controls and procedures (as definedinRules 13a-15(e)and 15d-15(e) promulgated under the Securities Exchange Act of 1934, as amended(Exchange Act))asofDecember 31, 2020. EOG's disclosure controlsand procedures are designed to providereasonableassurancethat information thatis required to be disclosed in the reports EOGfiles or submits under the Exchange Actisaccumulated and communicated to EOG's management, as appropriate, to allow timely decisions regarding required disclosure andisrecorded, processed, summarizedand reportedwithin the time periods specifiedinthe rules and formsofthe UnitedStatesSecuritiesand Exchange Commission. Basedonthat evaluation, EOG's principalexecutive officerand principalfinancial officer have concludedthat EOG's disclosure controlsand procedures were effectiveasofDecember 31,2020.

57 Management'sAnnual Report on Internal Control over Financial Reporting. EOG's managementisresponsible for establishingand maintaining adequate internalcontrol over financial reporting(as definedinRules 13a-15(f) and 15d-15(f) promulgatedunder theExchange Act).Even an effective systemofinternal control over financial reporting, no matter how welldesigned, hasinherentlimitations,including the possibilityofhuman error, circumvention of controlsoroverriding of controlsand, therefore,can provide only reasonableassurancewithrespecttoreliable financial reporting. Furthermore,the effectiveness of asystemofinternal control overfinancial reporting in future periods canchange as conditions change.

EOG'smanagementassessedthe effectiveness of EOG's internal controlover financial reportingasofDecember 31, 2020. In making thisassessment,itusedthe criteriaset forthbythe Committee of Sponsoring Organizationsofthe Treadway Commission (COSO)inInternal Control -Integrated Framework (2013). Based on thisassessment andsuchcriteria, EOG's management believes thatEOG's internalcontrol over financialreportingwas effective as of December 31, 2020. Seealso "Management'sResponsibilityfor FinancialReporting" appearing on page F-2 of thisreport,which is incorporated herein by reference.

The reportofEOG's independent registered publicaccounting firm relatingtothe consolidatedfinancial statements andeffectiveness of internal control over financial reporting is setforth on page F-3 of this report.

There were no changes in EOG's internal control over financial reporting thatoccurredduring the quarterended December 31, 2020, thathavemateriallyaffected, or are reasonablylikelytomaterially affect, EOG's internalcontrolover financialreporting.

ITEM 9B. Other Information

None.

PART III

ITEM10. Directors, Executive Officers and CorporateGovernance

The information required by thisItemisincorporated by referencefrom(i) EOG'sDefinitive Proxy Statement with respect to its 2021 AnnualMeeting of Stockholders to be filednot later than April 30, 2021 and (ii)Item1ofthis report, specifically theinformationtherein set forth underthe caption "InformationAbout OurExecutive Officers."

Pursuant to Rule303A.10 of the NewYork StockExchange and Item406 of RegulationS-K promulgatedunder the Securities Exchange Act of 1934, as amended, EOG has adopted aCode of Business Conductand Ethics for Directors, Officers and Employees (Code of Conduct) thatapplies to allEOG directors, officers andemployees,including EOG's principal executive officer, principal financial officerand principalaccounting officer. EOG hasalso adoptedaCode of Ethics forSenior Financial Officers (Code of Ethics) that, along withEOG's Code of Conduct, applies to EOG'sprincipalexecutive officer, principalfinancial officer, principal accounting officerand controllers.

Youcan access the Code of Conduct andCode of Ethicsonthe "Governance"page under "Investors" on EOG's website at www.eogresources.com, andany EOGstockholder who so requestsmay obtain aprinted copy of the Codeof Conductand Code of Ethics by submitting awritten request to EOG's CorporateSecretary.

EOG intends to disclose anyamendments to the CodeofConductorCode of Ethics, and any waivers withrespect to theCode of ConductorCode of Ethicsgranted to EOG's principal executive officer, principal financial officer, principal accounting officer,any of our controllers or any of our other employees performing similarfunctions, on itswebsite at www.eogresources.com within four business days of the amendment or waiver. In such case, the disclosure regardingthe amendment or waiver will remainavailableonEOG's website foratleast 12 months afterthe initial disclosure. There have been no waivers grantedwith respect to EOG'sCode of ConductorCode of Ethics.

58 ITEM11. Executive Compensation

The information required by thisItemisincorporated by referencefromEOG's DefinitiveProxy Statement with respect to its 2021 AnnualMeeting of Stockholders to be filednot later than April 30, 2021. TheCompensation Committee Report andrelated informationincorporated by referenceherein shallnot be deemed "soliciting material" or to be "filed"with theUnitedStates Securities and Exchange Commission, nor shallsuchinformation be incorporated by referenceinto any future filing underthe SecuritiesAct of 1933,asamended, or Securities Exchange Act of 1934, as amended, except to theextent that EOG specifically incorporates such information by reference intosuchafiling.

ITEM 12. SecurityOwnershipofCertain Beneficial Owners and Management and Related StockholderMatters

The information required by thisItemwithrespect to security ownershipofcertain beneficialownersand management is incorporated by referencefromEOG's DefinitiveProxy Statement with respect to its 2021 Annual MeetingofStockholders to be filednot laterthanApril30, 2021.

Equity Compensation Plan Information

StockPlansApproved by EOGStockholders. EOG'sstockholders approvedthe EOG Resources, Inc. 2008 Omnibus Equity CompensationPlan(2008 Plan) at the 2008 Annual Meeting of Stockholders in May 2008. At the 2010 Annual Meeting of Stockholders in April 2010 (2010 AnnualMeeting), an amendment to the2008 Planwas approved, pursuant to which the numberofshares of common stockavailablefor future grants of stockoptions,stock-settled stockappreciation rights(SARs), restricted stock, restricted stockunits, performanceunits and otherstock-based awards under the 2008 Planwas increased by an additional 13.8 millionshares, to an aggregate maximum of 25.8 million sharesplussharesunderlying forfeited or canceled grantsunder the prior stockplans referenced in the 2008 Plandocument.Atthe 2013 Annual MeetingofStockholders in May 2013, EOG's stockholders approvedthe Amendedand Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (Amended and Restated 2008 Plan). As more fullydiscussed in the Amendedand Restated2008Plandocument,the Amended and Restated 2008 Plan, among other things, authorizes an additional 31.0 million sharesofEOG commonstockfor grant under the plan andextendsthe expiration dateofthe plantoMay 2023.Under the Amended andRestated 2008 Plan, grantsmay be made to employees andnon-employeemembers of EOG'sBoard.

Also at the 2010 Annual Meeting, an amendment to theEOG Resources, Inc. EmployeeStock Purchase Plan (ESPP) was approved to increase the sharesavailable forgrant by 2.0 million shares. TheESPP wasoriginallyapprovedbyEOG's stockholders in 2001, and would have expiredonJuly1,2011. The amendment also extended the term of theESPP to December 31, 2019, unless terminatedearlier by its terms or by EOG. At the 2018 Annual Meeting of Stockholders in April 2018, stockholders approved an amendment andrestatement of the ESPP to (among other changes) increase the number of sharesavailable for grant by 2.5 million shares and furtherextend the term of theESPP to December 31, 2027, unless terminatedearlier by its termsorbyEOG.

Stock Plans Not Approved by EOG Stockholders. In December 2008, the Board approvedthe amendment and continuation of the 1996 Deferral Planasthe "EOG Resources, Inc.409ADeferredCompensation Plan" (DeferralPlan).Under the Deferral Plan (as subsequentlyamended), payment of up to 50% of base salary and 100% of annualcashbonus, director's fees, vestings of restricted stock units granted to non-employee directors(and dividendscredited thereon)under the 2008 Plan and 401(k) refunds (as definedinthe Deferral Plan)may be deferredinto aphantom stock account. In the phantom stock account, deferrals are treatedasifshares of EOG common stock were purchasedatthe closing stock priceonthe dateof deferral. Dividendsare credited quarterly and treatedasifreinvested in EOG common stock. Paymentofthe phantomstock accountismade in actualshares of EOG common stock in accordancewith the DeferralPlanand the individual's deferral election. Atotal of 540,000 sharesofEOG common stock have been authorizedbythe Board and registeredfor issuance under the Deferral Plan.AsofDecember 31, 2020, 368,745 phantom shareshad been issued. The Deferral Plan is currentlyEOG's only stockplanthathas not beenapprovedbyEOG's stockholders.

59 The following table sets forthdata forEOG's equitycompensation plans aggregated by thevarious plans approvedby EOG's stockholders andthose plans not approved by EOG's stockholders,ineachcase as of December31, 2020.

(c) NumberofSecurities (a) (b) RemainingAvailable Number of Securitiestobe Weighted-Average forFutureIssuanceUnder Issued Upon Exerciseof Exercise Priceof Equity Compensation Outstanding Options, Outstanding Options, Plans (Excluding Securities Plan Category Warrants andRights Warrants andRights (1) ReflectedinColumn(a))

EquityCompensation Plans ApprovedbyEOG Stockholders 11,753,761 (2) $84.08 3,891,544 (3) EquityCompensation Plans Not Approved by EOG Stockholders 248,363 (4) N/A 171,255 (5) Total 12,002,124 $84.08 4,062,799

(1) The weighted-average exercise priceiscalculated basedsolely on the exercise prices of the outstandingstock option and SAR grants and does not reflect shares thatwillbeissued upon the vesting of outstanding restricted stock unit and performanceunitgrants, or Deferral Planphantom shares, all of whichhave no exercise price. (2) Amount includes 954,949 outstanding restricted stock units, for which shares of EOG commonstockwillbeissued,onaone-for-one basis, upon the vesting of such grants. Amount also includes 612,951 outstanding performance units and assumes, for purposes of this table, (i) the application of a100% performance multiple upon the completionofeach of theremaining performance periodsinrespect of such performance unit grants and (ii) accordingly, the issuance, on aone-for-one basis, of an aggregate 612,951 shares of EOG common stockupon the vestingofsuch grants. As morefully discussed in Note7toConsolidated Financial Statements, upon the application of the relevantperformance multiple at the completion of eachofthe remaining performance periods in respectofsuch grants, (A) a minimumof76,785 and amaximum of 1,149,117performance units couldbeoutstanding and (B) accordingly, aminimum of 76,785 and amaximum of 1,149,117shares of EOG commonstock could be issued uponthe vesting of such grants. (3) Consists of (i) 1,996,101 shares remaining availablefor issuance under the Amended and Restated 2008 Plan and (ii) 1,895,443shares remainingavailable for purchase under the ESPP. Pursuant to the fungible share design of the Amended andRestated 2008 Plan, each share issued as aSAR or stock optionunder the Amendedand Restated2008 Plan countsas1.0 shareagainstthe aggregate plan share limit, and each share issued as a"full value award" (i.e., as restricted stock,restricted stock units or performance units) counts as 2.45 shares against the aggregate plan share limit.Thus, from the 1,996,101shares remaining available for issuanceunder the Amended and Restated 2008Plan, (i)the maximum number of shares we could issue as SAR and stock option awards is 1,996,101 (i.e., if all shares remainingavailable for issuanceunder the Amended and Restated 2008 Planare issued as SAR andstockoption awards) and (ii) the maximum number of shares we could issue as full value awards is 814,735 (i.e., if all shares remainingavailable for issuance under the Amended and Restated 2008 Plan areissued as full value awards). (4) ConsistsofsharesofEOG commonstock to be issued in accordance with the Deferral Plan and participant deferral elections (i.e., in respect of the 248,363 phantom shares issued and outstanding under the DeferralPlan as of December 31, 2020). (5) Represents phantomshares thatremain available forissuance underthe Deferral Plan.

ITEM13. CertainRelationships and RelatedTransactions, and Director Independence

The information required by thisItemisincorporated by referencefromEOG's DefinitiveProxyStatement with respecttoits 2021 AnnualMeeting of Stockholders to be filednot laterthanApril30, 2021.

ITEM14. Principal Accounting Fees and Services

The information required by thisItemisincorporated by referencefromEOG's DefinitiveProxyStatement with respecttoits 2021 AnnualMeeting of Stockholders to be filed not laterthanApril30, 2021.

60 PART IV

ITEM 15. Exhibits, Financial StatementSchedules

(a)(1) and (a)(2) Financial Statements and Financial Statement Schedule

See "Index to Financial Statements" setforth on page F-1.

(a)(3), (b) Exhibits

See pages E-1 through E-6 for alistingofthe exhibits.

ITEM 16. Form 10-K Summary

None.

61 EOG RESOURCES,INC. INDEX TO FINANCIAL STATEMENTS

Page Consolidated Financial Statements: Management's Responsibilityfor Financial Reporting F-2 Report of Independent Registered Public Accounting Firm F-3 Consolidated Statements of Income (Loss) andComprehensiveIncome (Loss) for Each of the Three Years in the Period Ended December31, 2020 F-6 Consolidated BalanceSheets -December31, 2020 and 2019 F-7 Consolidated Statements of Stockholders' Equity for Each of the ThreeYears in thePeriod Ended December 31, 2020 F-8 Consolidated Statements of Cash Flows for Each of the ThreeYears in thePeriod Ended December 31, 2020 F-9 Notes to Consolidated Financial Statements F-10 SupplementalInformation to Consolidated Financial Statements F-43

F-1 MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL REPORTING

The following consolidated financial statements of EOG Resources, Inc., togetherwithits subsidiaries(collectively, EOG),wereprepared by management, which is responsible for the integrity, objectivity andfair presentationofsuchfinancial statements. The statements have beenprepared in conformity withgenerally acceptedaccounting principles in the United StatesofAmericaand, accordingly, include someamounts that are basedonthe best estimates andjudgments of management.

EOG'smanagement is also responsible for establishing and maintaining adequateinternal controloverfinancial reporting as wellasdesigning andimplementing programs and controlstoprevent and detectfraud.The system of internal control of EOGisdesigned to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposesinaccordance withgenerally acceptedaccounting principlesinthe United States of America.Thissystem consistsof1)entitylevel controls, including writtenpolicies andguidelines relating to theethical conduct of business affairs, 2) general computer controls and3)process controlsoverinitiating,authorizing,recording, processing and reporting transactions. Even an effective internal control system, no matter howwelldesigned, hasinherent limitations,including the possibility of humanerror, circumvention of controls or overriding of controlsand, therefore, can provide only reasonableassurance with respecttoreliablefinancial reporting. Furthermore,the effectivenessofasystem of internal control overfinancial reporting in futureperiods canchange as conditions change.

The adequacyofEOG's financial controls and the accounting principlesemployedbyEOG in its financial reporting are under the general oversight of the AuditCommittee of the Board of Directors. No member of thiscommitteeisanofficeror employeeofEOG.Moreover, EOG'sindependent registeredpublicaccounting firm andinternalauditors havefull,free, separateand direct access to theAudit Committee andmeetwith thecommittee periodically to discuss accounting, auditing and financial reporting matters.

EOG'smanagement assessedthe effectivenessofEOG's internal controloverfinancial reportingasofDecember 31, 2020.Inmakingthis assessment, EOGused the criteria set forthbythe Committee of Sponsoring Organizationsofthe TreadwayCommission (COSO) in Internal Control -IntegratedFramework(2013).These criteria cover the control environment,riskassessment process, control activities, information and communication systems, and monitoring activities. Based on thisassessment and those criteria, management believes thatEOG maintained effective internal controlover financial reporting as of December31, 2020.

Deloitte &Touche LLP, independent registered publicaccounting firm,was engagedtoauditthe consolidated financialstatements of EOG and audit EOG'sinternalcontrol over financial reporting and issueareport thereon. In theconduct of the audits, Deloitte &Touche LLPwas givenunrestrictedaccess to allfinancial records and relateddata,includingall minutes of meetings of stockholders,the Board of Directors andcommitteesofthe Board of Directors. Management believes thatall representations made to Deloitte &Touche LLP during the audits were validand appropriate. Theiraudits were made in accordance with the standardsofthe PublicCompany Accounting Oversight Board (United States). Theirreport appearson page F-3.

WILLIAM R. THOMAS TIMOTHY K. DRIGGERS Chairman of theBoard and Executive VicePresident and Chief ChiefExecutive Officer Financial Officer

Houston, Texas February 25, 2021

F-2 REPORT OF INDEPENDENT REGISTEREDPUBLICACCOUNTING FIRM

To theStockholdersand theBoard of Directors of EOG Resources, Inc. Houston, Texas

Opinions on the Financial Statements and Internal Control over Financial Reporting

We have auditedthe accompanying consolidated balancesheetsofEOG Resources, Inc. and subsidiaries(the"Company") as of December 31, 2020 and 2019, the related consolidated statementsofincome andcomprehensive income,stockholders' equity, and cash flows for each of the three yearsinthe period endedDecember31, 2020, andthe related notes(collectively referred to as the “financial statements”).Wealso have auditedthe Company's internalcontroloverfinancial reporting as of December31, 2020, based on criteriaestablished in InternalControl —IntegratedFramework(2013) issuedbythe Committee of Sponsoring Organizations of the TreadwayCommission (COSO).

In our opinion, the financial statementsreferred to above present fairly, in allmaterialrespects, the financial position of the Company as of December31, 2020 and2019, and the resultsofits operations and its cash flows foreach of the threeyears in theperiodendedDecember 31,2020, in conformitywithaccounting principlesgenerally acceptedinthe UnitedStates of America.Also, in ouropinion, the Company maintained, in allmaterial respects,effective internalcontrol over financial reportingasofDecember31, 2020, based on the criteria established in Internal Control—Integrated Framework(2013) issued by COSO.

Basisfor Opinions

The Company's management is responsiblefor these financial statements,for maintaining effective internal control over financial reporting, and for its assessmentofthe effectiveness of internalcontrol overfinancial reporting, included in the accompanying Management’s Annual Report on Internal Controlover Financial Reporting.Our responsibility is to express an opinion on these financial statements andanopinion on the Company's internalcontrol over financial reportingbasedonour audits. We are apublic accounting firm registered with thePublicCompany Accounting Oversight Board (United States) (PCAOB)and arerequired to be independent with respecttothe Companyinaccordancewiththe U.S. federal securities laws andthe applicable rulesand regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance withthe standards of the PCAOB. Those standards require thatweplanand perform the audits to obtain reasonable assuranceabout whether the financialstatements arefree of material misstatement,whether due to error or fraud, and whethereffective internal control overfinancial reporting was maintainedinall materialrespects.

Our auditsofthe financialstatementsincluded performing procedures to assessthe risks of material misstatement of the financial statements, whetherdue to errororfraud, and performing procedures to respond to those risks. Such procedures includedexamining,onatest basis,evidenceregarding theamountsand disclosuresinthe financial statements. Our audits also includedevaluating the accountingprinciples used and significant estimates made by management, as wellasevaluating the overall presentation of the financial statements. Our audit of internalcontrol over financial reporting included obtaining an understanding of internalcontrol over financial reporting, assessing the riskthatamaterial weakness exists, and testing and evaluating the design andoperating effectiveness of internalcontrol based on the assessed risk. Our auditsalso included performing such other procedures as we considered necessary in the circumstances.Webelieve that ourauditsprovide a reasonablebasis for our opinions.

Definition and LimitationsofInternal ControloverFinancial Reporting

Acompany’s internal control over financial reporting is aprocess designed to provide reasonableassurance regarding the reliability of financial reporting andthe preparation of financial statementsfor externalpurposesinaccordancewithgenerally accepted accounting principles.Acompany’s internal control over financial reporting includes those policies andprocedures that (1)pertain to the maintenance of records that, in reasonabledetail, accurately and fairlyreflectthe transactions and dispositions of the assetsofthe company; (2) provide reasonable assurance that transactionsare recordedasnecessary to permit preparation of financialstatements in accordancewithgenerallyaccepted accounting principles, andthat receipts and expenditures of the company are being made only in accordance with authorizations of management anddirectorsofthe company; and(3) provide reasonableassurance regarding prevention or timely detectionofunauthorized acquisition, use, or disposition of the company’s assets that could have amaterial effectonthe financial statements.

F-3 Because of itsinherent limitations,internal control over financial reporting may notprevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk thatcontrolsmay becomeinadequate because of changes in conditions, or thatthe degreeofcompliance withthe policies or procedures maydeteriorate.

Critical AuditMatter

The critical auditmattercommunicated below is amatter arising from the current-period auditofthe financial statements that was communicated or required to be communicated to theaudit committee andthat (1)relates to accountsordisclosures that are material to thefinancial statements and (2)involvedour especiallychallenging,subjective, or complexjudgments. The communication of criticalaudit mattersdoes not alter in any wayour opinion on the financialstatements,taken as awhole, and we are not, by communicating the criticalauditmatter below, providing aseparateopinion on the criticalauditmatter or on the accountsordisclosures to whichitrelates.

Proved Oil and Gas Properties and Depletion andImpairment–CrudeOil andCondensate,NGLs, andNatural Gas Reserves—Refer to Notes1,13and 14 to the Financial Statements

CriticalAudit Matter Description

The Company’s proved oil and natural gaspropertiesare depleted usingthe units of production method and are evaluated for impairment by comparison to the future net cash flows of the underlying provedcrude oil, natural gas liquids (NGLs) and natural gas reserves. The development of the Company’s crude oil,NGLs andnatural gasreserve volumesand the related futurenet cash flows requires managementtomake significant estimates and scheduling assumptions related to the five-year development planfor proved undevelopedreserves, future crudeoil,NGLsand naturalgas prices, and future well costs.The Company’s reserve engineers estimate crude oil,NGLsand natural gasquantities usingthese estimates and assumptions and engineering data. Changes in these assumptions couldhaveasignificant impact on theamountofdepletionand anyprovedoil and gasimpairment. Proved oil andgas propertieswere$23 billionasofDecember31, 2020, and depletion and proved propertyimpairmentwere $3.2 billion and$1.3 billion, respectively, for the year then ended.

Giventhe significant judgments made by management,performing audit procedurestoevaluate the Company’s proved crude oil,NGLsand naturalgas reservequantities and the related future netcashflows including management’s estimates and assumptionsrelated to the five-yeardevelopment plan, future crude oil,NGLs and natural gaspricesand future wellcosts, requiredahighdegreeofauditorjudgment andanincreased extent of effort,including the need to involve our fairvalue specialists.

How the CriticalAudit Matter Was Addressed in theAudit

Our audit procedures related to management’s estimates and assumptions relatedtocrude oil,NGLsand natural gas reserve quantities andestimatesoffuture net cash flows includedthe following, among others:

• We tested the effectiveness of controlsoverthe Company’s estimation of provedcrude oil, NGLs and natural gas reserve quantities and related future net cash flows, includingcontrols relating to the five-year developmentplan, future crude oil,NGLs andnaturalgas prices andfuturewellcosts.

• We evaluatedthe reasonableness of management’s five-year development plan by comparingthe forecasts to: ◦ Historicalconversions of proved undeveloped reserves. ◦ Internal communications to management andthe Board of Directors. ◦ Approval for expenditures. ◦ Analyst andindustry reports for the Company andcertainofits peer companies.

• With the assistance of our fairvalue specialists, we evaluatedmanagement’s estimated futurecrude oil,NGLsand natural gaspricesby: ◦ Understanding the methodology used by management for development of the future prices and comparing the estimated pricestoanindependently determinedrange of prices. ◦ Comparing management’s estimatestopublished forward pricing indicesand third-party industrysources. ◦ Evaluating the historical realized price differentials incorporatedinthe future crude oil, NGLs and natural gas prices.

F-4 • We evaluated thereasonablenessofcapital expenditures (well costs) by comparing the estimateto: ◦ Historical developmentofsimilar wellsdrilled. ◦ Analyst andindustry reports.

• We evaluatedthe Company’s oil andnatural gas reserve volumesby: ◦ Comparingthe Company’s reserve volumes to historicalproduction volumes. ◦ Comparing the Company’s reserve volumes to thoseindependently developed by the independent petroleum consultants. ◦ Evaluating thereasonableness of the production volume decline curves. ◦ Understanding the experience, qualifications, and objectivityofthe Company’s reserve engineers and the independent petroleum consultants.

/s/ DELOITTE&TOUCHE LLP

Houston, Texas February 25, 2021

We have served as theCompany's auditor since 2002.

F-5 EOG RESOURCES,INC. CONSOLIDATED STATEMENTS OF INCOME(LOSS) AND COMPREHENSIVE INCOME (LOSS) (InThousands, Except PerShareData)

Year EndedDecember 31 2020 2019 2018 Operating Revenues and Other Crude Oil andCondensate $5,785,609 $9,612,532 $9,517,440 Natural Gas Liquids 667,514 784,818 1,127,510 Natural Gas 837,133 1,184,095 1,301,537 Gains (Losses) on Mark-to-MarketCommodityDerivativeContracts 1,144,737 180,275 (165,640) Gathering,Processing and Marketing 2,582,984 5,360,282 5,230,355 Gains (Losses) on Asset Dispositions, Net(46,883) 123,613 174,562 Other, Net60,954 134,358 89,635 Total 11,032,048 17,379,973 17,275,399 Operating Expenses Leaseand Well 1,063,374 1,366,993 1,282,678 TransportationCosts734,989 758,300 746,876 Gathering andProcessing Costs459,211 479,102 436,973 Exploration Costs 145,788 139,881 148,999 Dry HoleCosts 13,083 28,001 5,405 Impairments 2,099,780 517,896 347,021 Marketing Costs 2,697,729 5,351,524 5,203,243 Depreciation, Depletion andAmortization3,400,353 3,749,704 3,435,408 General andAdministrative 483,823 489,397 426,969 TaxesOtherThanIncome477,934 800,164 772,481 Total 11,576,064 13,680,962 12,806,053 Operating Income (Loss) (544,016) 3,699,011 4,469,346 OtherIncome, Net 10,228 31,385 16,704 Income (Loss) BeforeInterestExpense and Income Taxes (533,788) 3,730,396 4,486,050 Interest Expense Incurred 236,154 223,421 269,549 Capitalized(30,888)(38,292)(24,497) NetInterest Expense 205,266 185,129 245,052 Income (Loss) BeforeIncomeTaxes (739,054) 3,545,267 4,240,998 Income TaxProvision (Benefit) (134,482) 810,357 821,958 NetIncome (Loss) $(604,572) $2,734,910 $3,419,040 NetIncome (Loss) PerShare Basic $(1.04) $4.73 $5.93 Diluted $(1.04) $4.71 $5.89 Average NumberofCommon Shares Basic 578,949 577,670 576,578 Diluted 578,949 580,777 580,441 Comprehensive Income (Loss) NetIncome (Loss) $(604,572) $2,734,910 $3,419,040 OtherComprehensive Income (Loss) Foreign Currency Translation Adjustments (7,346) (2,883) 16,816 Other, NetofTax (330) (678) 1,123 Other Comprehensive Income(Loss) (7,676) (3,561) 17,939 Comprehensive Income (Loss) $(612,248) $2,731,349 $3,436,979

The accompanyingnotes areanintegralpart of these consolidated financial statements.

F-6 EOG RESOURCES,INC. CONSOLIDATED BALANCE SHEETS (InThousands,ExceptShare Data) At December3120202019

ASSETS Current Assets Cash andCashEquivalents$3,328,928 $2,027,972 AccountsReceivable,Net 1,522,256 2,001,658 Inventories 629,401 767,297 Assets from Price Risk Management Activities 64,559 1,299 Income TaxesReceivable 23,037 151,665 Other293,987 323,448 Total 5,862,168 5,273,339 Property, Plantand Equipment Oil and GasProperties (Successful EffortsMethod) 64,792,798 62,830,415 OtherProperty, Plant and Equipment 4,478,976 4,472,246 Total Property, Plant andEquipment 69,271,774 67,302,661 Less: AccumulatedDepreciation, Depletion andAmortization (40,673,147) (36,938,066) Total Property, Plant andEquipment, Net28,598,627 30,364,595 DeferredIncomeTaxes 2,127 2,363 OtherAssets 1,341,679 1,484,311 Total Assets $35,804,601 $37,124,608

LIABILITIESAND STOCKHOLDERS' EQUITY Current Liabilities Accounts Payable$1,681,193 $2,429,127 AccruedTaxesPayable 205,754 254,850 Dividends Payable 217,419 166,273 Liabilities from Price Risk Management Activities —20,194 Current PortionofLong-Term Debt 781,054 1,014,524 CurrentPortion of Operating LeaseLiabilities 295,089369,365 Other279,595 232,655 Total 3,460,104 4,486,988 Long-Term Debt 5,035,351 4,160,919 OtherLiabilities 2,147,932 1,789,884 DeferredIncome Taxes 4,859,327 5,046,101 Commitments and Contingencies (Note 8) Stockholders' Equity Common Stock, $0.01 Par, 1,280,000,000 SharesAuthorized and 583,694,850 Shares and 582,213,016 SharesIssuedatDecember31, 2020 and 2019, respectively 205,837 205,822 Additional Paid in Capital 5,945,024 5,817,475 AccumulatedOtherComprehensive Loss (12,328) (4,652) RetainedEarnings 14,169,969 15,648,604 Common Stock Held in Treasury, 124,265 Shares and298,820 SharesatDecember 31, 2020 and 2019, respectively (6,615) (26,533) Total Stockholders' Equity 20,301,887 21,640,716 Total Liabilitiesand Stockholders' Equity $35,804,601 $37,124,608 The accompanyingnotes areanintegralpart of these consolidated financial statements.

F-7 EOG RESOURCES,INC. CONSOLIDATED STATEMENTS OF STOCKHOLDERS'EQUITY (InThousands, Except PerShareData)

Accumulated Common Additional Other Stock Total Common Paid In Comprehensive Retained Held In Stockholders' Stock Capital Income (Loss) Earnings Treasury Equity BalanceatDecember31, 2017 $205,788 $5,536,547 $(19,297) $10,593,533 $(33,298)$ 16,283,273 Net Income —— —3,419,040 —3,419,040 Common Stock Issued UnderStock Plans 85,612 ———5,620 Common Stock Dividends Declared, $0.81 Per Share —— —(469,443)—(469,443) Other ComprehensiveIncome —— 17,939——17,939 ChangeinTreasury Stock-Stock Compensation Plans, Net —(35,118)——(13,336) (48,454) Restricted Stock and Restricted Stock Units, Net 8(3,891) ——3,883 — Stock-Based Compensation Expenses —155,337———155,337 Treasury Stock Issued as Compensation —307 ——569 876 Balance at December 31, 2018 205,804 5,658,794 (1,358) 13,543,130 (42,182) 19,364,188 Net Income —— —2,734,910 —2,734,910 Common Stock Issued UnderStock Plans 1(9) ———(8) Common Stock Dividends Declared, $1.0825 Per Share —— —(629,169)—(629,169) Other Comprehensive Loss —— (3,561) —— (3,561) ChangeinTreasury Stock-Stock Compensation Plans, Net —(10,637)——3,784 (6,853) Restricted Stock and Restricted Stock Units, Net 17 (4,566) ——4,549 — Stock-Based Compensation Expenses —174,738———174,738 Treasury Stock Issued as Compensation —(845) ——7,316 6,471 Cumulative EffectofAccounting Changes —— 267 (267) —— Balance at December 31, 2019 205,822 5,817,475 (4,652) 15,648,604 (26,533) 21,640,716 Net Loss —— —(604,572)—(604,572) Common Stock Issued UnderStock Plans —— ———— Common Stock DividendsDeclared, $1.50 Per Share —— —(874,063)—(874,063) Other Comprehensive Loss —— (7,676) —— (7,676) ChangeinTreasury Stock-Stock Compensation Plans, Net —(9,152) ——9,089 (63) Restricted Stock and Restricted Stock Units, Net 15 (9,310) ——9,295 — Stock-Based Compensation Expenses —146,396———146,396 Treasury Stock Issued as Compensation —(385) ——1,534 1,149 BalanceatDecember 31, 2020 $205,837 $5,945,024 $(12,328) $14,169,969 $(6,615)$ 20,301,887

The accompanyingnotes areanintegralpart of these consolidated financial statements.

F-8 EOG RESOURCES,INC. CONSOLIDATED STATEMENTSOFCASH FLOWS (In Thousands)

Year Ended December 31 2020 2019 2018 Cash Flows fromOperating Activities Reconciliation of Net Income (Loss) to NetCashProvided by Operating Activities: Net Income (Loss) $(604,572)$ 2,734,910 $3,419,040 Items Not Requiring (Providing) Cash Depreciation, Depletion and Amortization 3,400,353 3,749,704 3,435,408 Impairments 2,099,780 517,896 347,021 Stock-BasedCompensation Expenses 146,396 174,738 155,337 Deferred IncomeTaxes (186,390) 631,658 894,156 (Gains) Losses on Asset Dispositions, Net46,883 (123,613) (174,562) Other, Net 12,8264,496 7,066 Dry Hole Costs 13,08328,001 5,405 Mark-to-Market CommodityDerivative Contracts Total (Gains) Losses (1,144,737) (180,275) 165,640 Net Cash Received from (Payments for) Settlements of CommodityDerivative Contracts 1,070,647 231,229 (258,906) Other, Net 1,354 962 3,108 Changes in Components of Working Capital andOther Assets and Liabilities AccountsReceivable 466,523 (91,792) (368,180) Inventories 122,647 90,284 (395,408) AccountsPayable (795,267) 168,539 439,347 Accrued TaxesPayable (49,096) 40,122(92,461) OtherAssets 324,521358,001 (125,435) OtherLiabilities 8,098 (56,619) 10,949 Changes in Components of Working Capital Associated withInvestingand Financing Activities 74,734 (115,061) 301,083 Net Cash ProvidedbyOperating Activities 5,007,783 8,163,180 7,768,608 Investing Cash Flows Additions to Oil andGas Properties (3,243,474) (6,151,885) (5,839,294) Additions to OtherProperty, Plant and Equipment(221,226)(270,641)(237,181) Proceeds fromSales of Assets191,928 140,292 227,446 Other Investing Activities —(10,000) (19,993) Changes in Components of Working Capital AssociatedwithInvesting Activities (74,734) 115,061 (301,140) Net Cash Used in Investing Activities (3,347,506) (6,177,173) (6,170,162) Financing Cash Flows Long-Term Debt Borrowings 1,483,852 —— Long-Term Debt Repayments (1,000,000) (900,000) (350,000) Dividends Paid (820,823) (588,200) (438,045) Treasury Stock Purchased (16,130)(25,152) (63,456) Proceeds fromStock Options Exercised andEmployee Stock Purchase Plan 16,169 17,946 20,560 Debt Issuance Costs(2,649) (5,016) — Repayment of Finance Lease Liabilities (19,444) (12,899)(8,219) Changes in Components of Working Capital Associatedwith Financing Activities ——57 NetCash Used in Financing Activities (359,025) (1,513,321) (839,103) EffectofExchange Rate Changes on Cash (296)(348) (37,937) Increase in Cash and Cash Equivalents 1,300,956 472,338 721,406 Cash and Cash Equivalents at BeginningofYear 2,027,972 1,555,634 834,228 Cash and Cash Equivalents at End of Year $3,328,928$2,027,972 $1,555,634

Theaccompanyingnotes areanintegralpart of these consolidated financial statements.

F-9 EOG RESOURCES,INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Summary of SignificantAccountingPolicies

Principles of Consolidation. Theconsolidatedfinancial statements of EOG Resources, Inc. (EOG)include the accountsofall domestic and foreignsubsidiaries.Investments in unconsolidatedaffiliates,inwhich EOG is abletoexercise significant influence, areaccountedfor using the equity method.All intercompany accountsand transactionshave been eliminated.

The preparation of financialstatements in conformity withaccounting principles generally accepted in the United StatesofAmerica (U.S.GAAP) requiresmanagementtomake estimates andassumptions thataffectthe reportedamounts of assets andliabilitiesand disclosureofcontingent assetsand liabilitiesatthe date of the financial statements and thereported amounts of revenuesand expensesduring thereporting period. Actualresults could differ from thoseestimates.

Financial Instruments. EOG'sfinancial instruments consist of cash and cash equivalents, commodity derivative contracts, accounts receivable,accounts payableand current andlong-termdebt. The carrying values of cash and cash equivalents, commodity derivative contracts, accountsreceivableand accounts payable approximate fair value(seeNotes 2and 12).

EffectiveJanuary 1, 2020, EOGadopted the provisions of Accounting Standards Update(ASU) 2016-13, "Measurement of Credit LossesonFinancial Instruments"(ASU 2016-13). ASU 2016-13 changes the impairmentmodel for financial assetsand certain otherinstrumentsbyrequiring entitiestoadopt aforward-looking expectedlossmodel that will result in earlier recognition of credit losses. EOGelected to adopt ASU 2016-13 using the modifiedretrospective approach with acumulative effect adjustmenttoretained earnings as of the effectivedate. Financial resultsreported in periods prior to January 1, 2020, are unchanged. EOG assessed itsapplicablefinancial assets, whichare primarily its accounts receivablefrom hydrocarbon sales and joint interest billings to third-party companies, including foreign state-ownedentities in the oil andgas industry. Basedonits assessment andvarious potentialremedies ensuringcollection, EOGdid not record an impact to retained earnings upon adoption and expects current andfuturecredit lossestobeimmaterial. EOG continuestomonitor the credit risk from third-party companies to determine if expected creditlosses maybecomematerial.

Cash and CashEquivalents. EOGrecords as cash equivalentsall highlyliquid short-term investmentswithoriginal maturities of three monthsorless.

Oil and Gas Operations. EOGaccountsfor itscrude oil and natural gasexploration and production activities under thesuccessful effortsmethodofaccounting.

Oil andgas lease acquisition costsare capitalized whenincurred. Unprovedproperties withacquisition coststhatare not individuallysignificant areaggregated, and the portion of suchcostsestimated to be nonproductive is amortized overthe remaininglease term. Unprovedproperties withindividually significant acquisitioncostsare reviewedindividually for impairment.Ifthe unproved propertiesare determined to be productive, the appropriate related costs are transferred to proved oiland gasproperties.Lease rentalsare expensed as incurred.

Oil andgas exploration costs, other thanthe costsofdrilling exploratory wells, are expensedasincurred. Thecosts of drilling exploratory wells are capitalized pending determination of whetherEOG hasdiscovered commercial quantities of proved reserves. If commercial quantities of provedreservesare not discovered,such drilling costsare expensed. In some circumstances, it maybeuncertain whethercommercial quantitiesofprovedreserves have been discovered when drilling has beencompleted.Such exploratory welldrilling costs maycontinue to be capitalizedifthe estimatedreserve quantity is sufficienttojustify its completionasaproducing well andsufficientprogressinassessing the reserves and the economicand operating viabilityofthe project is being made (seeNote16). Costs to develop provedreserves, including the costs of all development wellsand related equipment used in theproduction of crude oil andnatural gas, arecapitalized.

F-10 Depreciation, depletion and amortizationofthe cost of proved oil andgas properties is calculatedusing the unit-of- production method. Thereserve base usedtocalculate depreciation,depletion and amortization for leasehold acquisition costs and the cost to acquire proved properties is thesum of proveddeveloped reservesand proved undevelopedreserves. With respect to leaseand wellequipment costs, which include development costs and successful exploration drilling costs, the reserve base includes only proved developed reserves. Estimated future dismantlement, restoration and abandonment costs,net of salvage values, aretaken intoaccount.

Oil andgas properties are grouped in accordancewiththe provisions of the Extractive Industries-Oil andGas Topic of the Financial Accounting Standards Board (FASB)Accounting Standards Codification (ASC). Thebasis forgrouping is a reasonable aggregation of properties withacommon geologicalstructural feature or stratigraphic condition, such as areservoir or field.

Amortizationratesare updatedquarterlytoreflect:1)the additionofcapital costs, 2) reserve revisions (upwards or downwards)and additions, 3) propertyacquisitions and/or property dispositionsand 4) impairments.

When circumstances indicate that proved oiland gas propertiesmay be impaired,EOG comparesexpected undiscountedfuture cash flows at adepreciation, depletion and amortizationgroup level to the unamortized capitalized cost of the asset.Ifthe expected undiscountedfuture cash flows, based on EOG'sestimateof(and assumptions regarding) future crude oil,natural gas liquids(NGLs)and natural gasprices, operating costs, development expenditures, anticipatedproduction from proved reservesand otherrelevant data,are lower thanthe unamortized capitalized cost, the capitalized costisreduced to fair value. Fairvalueisgenerally calculated usingthe IncomeApproachdescribed in the Fair Value Measurement Topic of the ASC.Incertaininstances, EOGutilizes accepted offers from third-party purchasers as the basisfor determining fair value.

Inventories, consisting primarilyoftubular goods, materials forcompletion operations and well equipmentheld foruse in the explorationfor, and developmentand production of, crude oil,NGLsand natural gasreserves, are carried at the lower of cost and netrealizable value with adjustments made,asappropriate,torecognize anyreductions in value.

Revenue Recognition. Effective January1,2018, EOGadopted theprovisions of ASU 2014-09, "Revenue From Contracts With Customers" (ASU 2014-09). ASU 2014-09 and otherrelatedASUs require entities to recognizerevenue to depict the transfer of promisedgoods or servicestocustomers in an amount thatreflects the consideration to which the entity expectstobeentitledinexchangefor those goodsorservices. EOGelected to adopt ASU2014-09 using the modified retrospective approach, which required EOG to recognize in retained earnings the cumulative effect at the dateofadoption for allexisting contracts with customers whichwerenot substantially complete as of January 1, 2018. Therewas no impactto retained earnings upon adoptionofASU 2014-09.

EOG presentsdisaggregatedrevenues by type of commoditywithin itsConsolidated StatementsofIncome(Loss)and Comprehensive Income (Loss) andbygeographic areas definedasoperating segments. See Note11.

In connection withthe adoptionofASU 2014-09, EOG presentsnatural gas processing fees relatingtocertain processing and marketing agreements within its United States segmentasGathering and Processing Costs, insteadofasa deduction to Revenueswithinits Consolidated Statements of Income(Loss) and Comprehensive Income(Loss).Therewas no impacttooperatingincome, net incomeorcashflows resultingfrom changestothe presentation of natural gasprocessing fees. The impacts of the adoption of ASU 2014-09 for the yearendedDecember31, 2018, were as follows (inthousands):

F-11 Amounts Without Adoption of ASU As Reported 2014-09 Effect of Change

OperatingRevenues andOther Crude Oil andCondensate $9,517,440 $9,517,440 $— Natural Gas Liquids 1,127,510 1,121,237 6,273 Natural Gas 1,301,537 1,104,095 197,442 Gathering, Processing and Marketing 5,230,355 5,211,136 19,219 Total Operating Revenues andOther 17,275,399 17,052,465 222,934 OperatingExpenses Gathering and Processing Costs 436,973 233,258 203,715 Marketing Costs 5,203,243 5,184,024 19,219 Total Operating Expenses12,806,053 12,583,119 222,934 OperatingIncome4,469,346 4,469,346 —

Revenuesare recognizedfor the saleofcrude oil andcondensate,NGLsand natural gas at the pointcontrol of the product is transferred to thecustomer,typicallywhenproduction is delivered and title or risk of loss transfers to thecustomer. Arrangements for suchsales are evidenced by signedcontractswithprices typically basedonstated market indices, withcertain adjustmentsfor product qualityand geographiclocation. As EOG typicallyinvoices customers shortlyafter performance obligations have been fulfilled, contractassets andcontractliabilities arenot recognized. Thebalances of accountsreceivable from contractswithcustomers as of December 31, 2020 and2019and upon adoption of ASU2014-09 effective January1, 2018, were $1,337 million, $1,619 million and $1,460 million, respectively, and were included in Accounts Receivable,Net on theConsolidated BalanceSheets. Lossesincurredonreceivablesfromcontractswith customers areinfrequent and have been immaterial.

CrudeOil andCondensate.EOG sells itscrude oiland condensate productionatthe wellhead or further downstream at acontractually-specified delivery point.Revenueisrecognized when control transfers to thecustomerbased on contract termswhich reflectprevailing marketprices. Anycostsincurred prior to the transfer of control, such as gathering and transportation, arerecognized as Operating Expenses.

Natural GasLiquids.EOG delivers certainofits natural gas productiontoeitherEOG-ownedprocessing facilitiesor third-partyprocessingfacilities, where extraction of NGLs occurs. For EOG-ownedfacilities, revenue is recognizedafter processing upon transfer of NGLstoacustomer. For third-party facilities, extracted NGLs are soldtothe ownerofthe processing facilityatthe tailgate, or EOG takespossession and sells theextractedNGLsatthe tailgate or exercises its option to sell further downstreamtovarious customers. Under typicalarrangements for third-partyfacilities, revenue is recognized after processing upon the transfer of control of the NGLs,either at the tailgateofthe processing plant or further downstream. EOG recognizes revenuesbasedoncontracttermswhich reflectprevailing market prices, with processing fees recognized as Gathering and Processing Costs.

Natural Gas.EOG sells its natural gas production either at the wellhead or further downstream at acontractually- specified delivery point.Inconnection withthe extraction of NGLs, EOG sells residue gasunder separateagreements. Typically, EOG takes possession of the naturalgas at the tailgateofthe processing facility and sells it at thetailgate or further downstream.Ineachcase, EOG recognizesrevenues when control transfers to the customer,basedoncontractterms which reflect prevailing market prices.

F-12 Gathering, Processing andMarketing.Gathering,processing and marketing revenuesrepresent sales of third-party crude oiland condensate,NGLsand natural gas, as wellasfeesassociated with gathering and processing third-partynaturalgas and revenues from sales of EOG-owned sand. EOG evaluateswhether it is theprincipal or agent underthese transactions. As control of the underlyingcommodity is transferredtoEOG prior to thegathering, processing and marketing activities,EOG considers itselfthe principalofthese arrangements. Accordingly, EOG recognizes these transactionsonagross basis. Purchasesofthird-partycommoditiesare recorded as Marketing Costs, withsales of third-partycommodities andfeesreceived forgathering and processing recordedasGathering, Processing andMarketing revenues.

OtherProperty,Plant and Equipment.Other property,plant and equipmentconsistsofgathering and processing assets, compressors, buildings and leasehold improvements, sand processing assets, computer hardware andsoftware, vehicles, and furniture andfixtures.Other property, plant and equipmentisgenerallydepreciated on astraight-linebasis overthe estimated useful lives of theproperty, plant andequipment, which range from 3years to 45 years.

CapitalizedInterest Costs. Interestcostshave been capitalized as apart of the historical costofunprovedoil andgas properties.The amount capitalized is an allocation of the interest costincurred during the reportingperiod. Capitalized interest is computedonly during the exploration and development phases and ceases once production begins. Theinterestrate used for capitalization purposesisbased on theinterest rates on EOG's outstanding borrowings. Thecapitalizationofinterest is excludedonsignificant acquisitions of unproved oil andgas properties financedthrough non-interest-bearing instruments,such as theissuance of shares of CommonStock,orthrough non-cash property exchanges.

Accounting for Risk Management Activities. Derivative instruments are recorded on the balance sheet as eitheran assetorliability measured at fairvalue, and changes in thederivative's fairvalue arerecognizedcurrentlyinearnings unless specifichedge accounting criteria aremet. During the three-year period endedDecember31, 2020, EOG electednot to designateany of itsfinancialcommodity derivative instruments as accounting hedges and, accordingly, changesinthe fair value of these outstandingderivative instrumentsare recognized as gains or lossesinthe period of change.The gains or losses are recordedasGains(Losses)onMark-to-Market CommodityDerivativeContracts on the Consolidated Statements of Income (Loss) andComprehensive Income (Loss). Therelated cash flow impact of settledcontracts is reflected as cash flows from operating activities. EOG employs netpresentation of derivativeassets and liabilities for financialreporting purposes when such assets and liabilities arewith the same counterpartyand subjecttoamaster netting arrangement. SeeNote12.

Income Taxes. Incometaxesare accounted for using the asset and liabilityapproach. Under thisapproach, deferred tax assetsand liabilitiesare recognized basedonanticipated future tax consequencesattributabletodifferences between financialstatement carryingamounts of assets and liabilities and their respective tax basis.EOG assesses the realizability of deferred taxassets and recognizes valuation allowances as appropriate.See Note6.

Foreign Currency Translation. TheUnited States dollar is the functionalcurrencyfor allofEOG's consolidated subsidiariesexcept forits Canadiansubsidiaries, for whichthe functional currencyisthe Canadian dollar, and itsUnited Kingdom subsidiary (whichwas sold in thefourth quarterof2018),for which thefunctional currency wasthe British pound. Forsubsidiarieswhose functionalcurrency is deemed to be other than theUnited Statesdollar,asset andliability accounts are translated at year-end exchange rates andrevenuesand expensesare translatedataverage exchange rates prevailing during the year. Translation adjustmentsare included in Accumulated Other Comprehensive Loss on the Consolidated BalanceSheets. Any gains or losses on transactions or monetary assetsorliabilities in currencies other thanthe functional currencyare included in netincomeinthe current period. SeeNotes 4and 17.

NetIncome (Loss) PerShare. Basic netincome(loss) pershare is computed on the basisofthe weighted-average number of common sharesoutstanding during the period. Diluted net income (loss)per share is computedbased upon the weighted-average number of common sharesoutstanding during the periodplusthe assumedissuance of common shares for all potentially dilutive securities. See Note9.

Stock-BasedCompensation.EOG measuresthe cost of employeeservicesreceivedinexchange for an award of equity instruments based on thegrant-date fair value of the award. See Note 7.

Leases. Effective January 1, 2019, EOG adoptedthe provisions of ASU 2016-02, "Leases(Topic 842)" (ASU 2016-02). ASU 2016-02 and otherrelatedASUsrequire thatlessees recognize aright-of-use(ROU) asset andrelated lease liability,representing the obligation to make leasepayments forcertain leasetransactions, on the Consolidated Balance Sheets and disclose additional leasing information.

F-13 EOGelected to adopt ASU 2016-02 and other related ASUs using the modified retrospective approach witha cumulative-effectadjustment to the opening balanceofretained earnings as of the effective date.Financial results reportedin periods prior to January 1, 2019, are unchanged. Additionally,EOG electedthe package of practical expedientswithin ASU 2016-02 thatallows an entity to notreassessprior to theeffective date (i) whetherany expiredorexisting contracts are or containleases, (ii)the leaseclassificationfor any expired or existing leases, or (iii) initial direct costs for any existing leases, but did not electthe practical expedient of hindsight when determining the leasetermofexisting contracts at theeffective date. EOG also electedthe practical expedientunder ASU 2018-01, "Leases(Topic842)-LandEasementPractical Expedient for Transition to Topic842," and did not evaluate existing or expired landeasementsnot previously accountedfor as leasesprior to theJanuary 1, 2019 effective date. Therewas no impacttoretainedearningsupon adoption of ASU 2016-02 andother related ASUs.

In the ordinarycourse of business, EOG enters intocontracts for drilling, fracturing, compression, realestateand other services which containequipment andother assetsand thatmeetthe definitionofaleaseunder ASU 2016-02. Theleaseterm for these contracts,whichincludesany renewals at EOG'soption thatare reasonablycertaintobeexercised, ranges from one monthto30years.

ROU assetsand related liabilities are recognized on the commencement dateonthe ConsolidatedBalanceSheets basedonfuturelease payments, discounted based on the rateimplicit in the contract, if readily determinable, or EOG's incremental borrowingratecommensuratewiththe leaseterm of thecontract.EOG estimates its incremental borrowing rate basedonthe approximate rate required to borrow on acollateralized basis. Contracts withlease terms of lessthan 12 months are notrecorded on the Consolidated BalanceSheets, butinsteadare disclosedasshort-term leasecost. EOG haselectednot to separate non-lease components from allleases,excluding those forfracturing services, realestateand saltwaterdisposal, as leasepayments underthese contractscontainsignificant non-lease components, suchaslabor and operating costs.See Note 18.

RecentlyIssued Accounting Standards. In March 2020, the FASB issuedASU 2020-04, "Reference Rate Reform (Topic 848)"(ASU 2020-04), whichprovidesoptionalexpedients andexceptions for accounting treatment of contracts which are affected by the anticipated discontinuation of the London InterBank OfferedRate(LIBOR) andother ratesresultingfrom ratereform.Contractterms that aremodifieddue to the replacement of areferencerate are not requiredtoberemeasured or reassessedunder relevant accounting standards. Early adoption is permitted. ASU 2020-04 covers certain contracts which referencethese rates and thatare enteredinto on or before December 31, 2022. EOG is evaluatingthe provisions of ASU 2020-04 and hasnot determinedthe full impactonits consolidated financial statements and related disclosures related to its $2.0 billion senior unsecuredRevolvingCredit Agreement.

In December 2019, the FASB issuedASU 2019-12, "Income Taxes(Topic740) - Simplifying the Accounting for Income Taxes" (ASU 2019-12), whichamends certain aspectsofaccounting for income taxes.ASU 2019-12 removes specific exceptions withinexisting U.S. GAAP related to the incremental approach for intraperiod taxallocation and to the general methodologyfor calculating incometaxesininterim periods, among otherchanges. ASU2019-12 also requires an entity to reflect theeffect of an enacted change in tax laws or rates in theannualeffective tax rate computation in the interimperiodthat includesthe enactmentdate, among otherrequirements. ASU 2019-12 is effective forinterim and annualperiods beginning after December15, 2020, andearly adoption is permitted.EOG willadopt ASU2019-12 effective January 1, 2021,withall of theanticipatedand applicableeffects to be requiredonaprospective basis. EOGdoesnot expect the adoption of ASU 2019-12 to have amaterialimpact on its consolidated financial statementsand related disclosures.

F-14 2. Long-TermDebt

Long-Term Debt at December 31, 2020 and2019consistedofthe following(in thousands): 2020 2019

4.40% Senior Notes due 2020 $—$500,000 2.45%Senior Notes due 2020 —500,000 4.100% Senior Notes due 2021 750,000 750,000 2.625% Senior Notes due 2023 1,250,000 1,250,000 3.15% Senior Notes due 2025 500,000 500,000 4.15% Senior Notes due 2026 750,000 750,000 6.65% Senior Notes due 2028 140,000 140,000 4.375% Senior Notes due 2030 750,000 — 3.90% Senior Notes due 2035 500,000 500,000 5.10% Senior Notes due 2036 250,000 250,000 4.950% Senior Notes due 2050 750,000 — Long-Term Debt 5,640,000 5,140,000 Finance Leases (seeNote18) 212,217 57,900 Less: Current Portion of Long-Term Debt 781,054 1,014,524 Unamortized DebtDiscount 30,931 19,528 Debt Issuance Costs4,881 2,929 TotalLong-Term Debt $5,035,351 $4,160,919

At December31, 2020, the aggregate annualmaturities of long-term debt (excludingfinance leaseobligations)were $750 millionin2021, zero in 2022, $1.25 billion in 2023,zeroin2024 and$500million in 2025.

At December 31, 2020 and 2019, EOGhad no outstandingcommercial paper borrowings and did not utilize any commercial paperborrowings during 2020 and2019.

On February 1, 2021, EOG repaid uponmaturity the$750million aggregateprincipalamount of its 4.100% Senior Notesdue 2021.

On June 1, 2020, EOG repaid upon maturitythe $500 million aggregate principal amount of its4.40% Senior Notes due 2020.

On April 14,2020, EOG closed on its offering of $750 million aggregateprincipal amount of its 4.375% Senior Notes due 2030 and $750 millionaggregateprincipalamount of its 4.950% Senior Notesdue 2050 (together, theNotes).Interest on the Notesispayablesemi-annually in arrears on April 15 and October 15 of each year, beginning on October 15, 2020. EOG receivednet proceedsof$1.48 billionfromthe issuance of the Notes, whichwereusedtorepaythe 4.40% Senior Notesdue 2020 when theymaturedonJune 1, 2020 (see below), and for general corporatepurposes, including the funding of capital expenditures.

On April1,2020, EOG repaid upon maturity the $500millionaggregateprincipalamountofits 2.45% Senior Notes due 2020.

On June 27, 2019, EOG enteredinto anew $2.0 billion senior unsecured Revolving Credit Agreement (the Agreement) withdomesticand foreign lenders (Banks). TheAgreement replacedEOG's $2.0 billion senior unsecured Revolving Credit Agreement,dated as of July21, 2015, withdomesticand foreign lenders, whichhad ascheduled maturity date of July 21,2020 and whichwas terminated by EOG(without penalty), effective as of June 27, 2019, in connection with the execution of the Agreement.

F-15 TheAgreement has ascheduled maturity dateofJune27, 2024,and includes an option for EOG to extend, on up to twooccasions,the term forsuccessive one-year periods subjecttocertain termsand conditions. The Agreement (i) commits the Banks to provide advances up to an aggregate principalamount of $2.0 billion at anyone time outstanding, withanoption for EOG to request increases in theaggregate commitmentstoanamount not to exceed$3.0 billion, subject to certain terms and conditions and (ii) includesaswingline subfacility and aletter of credit subfacility.Advances underthe Agreement will accrue interest based, at EOG's option,oneitherthe LIBOR plus an applicablemargin(Eurodollarrate) or the base rate (asdefined in theAgreement)plus an applicable margin.The Agreementcontains representations, warranties,covenants andeventsof default thatEOG believes are customary for investment-grade,senior unsecuredcommercial bank credit agreements, including afinancialcovenantfor the maintenance of aratio of total debt-to-capitalization (assuchterms are definedinthe Agreement)of no greater than65%. At December 31, 2020, EOGwas in compliancewiththisfinancialcovenant. At December31, 2020 and December 31, 2019, there were no borrowings or letters of credit outstanding under the Agreement.The Eurodollar rate and base rate(inclusive of the applicable margin), had there been any amountsborrowedunder the AgreementatDecember 31, 2020, would have been1.04% and 3.25%, respectively.

On June 3, 2019, EOGrepaidupon maturitythe $900 million aggregateprincipalamount of its5.625% Senior Notes due 2019.

3. Stockholders' Equity

Common Stock. In September 2001, EOG'sBoard of Directors (Board) authorized the purchase of an aggregate maximum of 10 million shares of Common Stockthatsuperseded allprevious authorizations. At December 31,2020, 6,386,200 shares remainedavailablefor purchaseunder thisauthorization. EOGlastpurchased shares of its Common Stock under thisauthorizationinMarch 2003. In addition, shares of Common Stockare from time to time withheld by,orreturnedto, EOG in satisfaction of tax withholding obligations arising upon the exercise of employeestockoptions or stock-settledstock appreciation rights(SARs), the vesting of restrictedstock, restrictedstock unit or performance unit grants or in payment of the exercise priceofemployeestockoptions. Such shareswithheldorreturned do not count againstthe Board authorization discussed above.Sharespurchased, withheldand returned areheld in treasuryfor,among other purposes, fulfilling any obligations arising underEOG's stock-basedcompensation plans and any other approvedtransactions or activitiesfor which such shares of CommonStock mayberequired.

On February 25, 2021, the Boardincreased the quarterly cash dividend on the common stockfromthe previous $0.375 per share to $0.4125per share, effective beginning withthe dividend to be paid on April 30, 2021, to stockholders of recordas of April 16, 2021.

On February 27, 2020, the Board increasedthe quarterly cash dividend on the common stock from the previous $0.2875 per share to $0.375 per share,effective beginning withthe dividend to be paid on April 30,2020, to stockholders of record as of April16, 2020.

On May 2, 2019, the Board increased the quarterly cash dividend on the common stockfromthe previous $0.22 per share to $0.2875per share,effective beginning withthe dividend paidonJuly31, 2019, to stockholders of record as of July17, 2019.

On August 2, 2018, the Board increased the quarterlycashdividend on thecommon stockfromthe previous$0.1850 per share to $0.22per share, effective beginning withthe dividend paid on October31, 2018, to stockholders of record as of October 17, 2018. On February 27, 2018, the Board increased the quarterlycashdividend on the commonstock from the previous$0.1675 per share to $0.1850 per share,effective beginning withthe dividend paidonApril30, 2018, to stockholders of record as of April 16, 2018.

F-16 Thefollowing summarizesCommon Stockactivityfor each of the yearsended December31, 2018, 2019 and 2020 (in thousands): Common Shares Issued Treasury Outstanding

Balance at December31, 2017 578,828 (351) 578,477 Common StockIssuedUnderStock-Based CompensationPlans 1,580—1,580 Treasury StockPurchased (1) —(539) (539) Common StockIssuedUnderEmployeeStock Purchase Plan—180180 Treasury StockIssuedUnderStock-BasedCompensationPlans —325 325 BalanceatDecember31, 2018 580,408 (385) 580,023 Common StockIssuedUnderStock-Based CompensationPlans 1,688 —1,688 Treasury StockPurchased (1) —(310) (310) Common StockIssuedUnderEmployeeStock Purchase Plan117 106 223 Treasury Stock Issued UnderStock-BasedCompensationPlans —290 290 BalanceatDecember31, 2019 582,213 (299) 581,914 Common StockIssuedUnderStock-Based CompensationPlans 1,482 —1,482 Treasury StockPurchased (1) —(389) (389) Common StockIssuedUnderEmployeeStock Purchase Plan—377377 Treasury StockIssuedUnderStock-BasedCompensationPlans—187187 BalanceatDecember31, 2020 583,695 (124) 583,571

(1) Represents shares that were withheld by or returned to EOG (i) in satisfaction of taxwithholding obligations thatarose uponthe exercise of employee stock optionsorSARs or the vesting of restrictedstock, restricted stock unit or performance unit grants or (ii) in payment of the exercise price of employee stock options.

Preferred Stock.EOG currentlyhas oneauthorizedseries of preferred stock. As of December31, 2020, there were no sharesofpreferredstock outstanding.

F-17 4. AccumulatedOtherComprehensive Loss

Accumulated othercomprehensive loss includes certain transactions thathavegenerally been reportedinthe ConsolidatedStatements of Stockholders' Equity. ThecomponentsofAccumulatedOtherComprehensive Loss at December 31, 2020 and2019 consistedofthe following (in thousands):

Foreign Currency Translation Adjustment OtherTotal

December31, 2018 $174 $(1,532) $(1,358) Cumulative effect of accounting changes —267 267 Other comprehensiveloss before taxes (2,883) (533) (3,416) Taxeffects—(145) (145) Other comprehensiveloss (2,883) (678) (3,561) December 31, 2019 (2,709) (1,943) (4,652) Other comprehensiveloss before taxes (7,346) (183) (7,529) Taxeffects—(147) (147) Other comprehensiveloss (7,346) (330) (7,676) December 31, 2020 $(10,055) $(2,273) $(12,328)

No significant amount wasreclassifiedout of AccumulatedOtherComprehensive Loss during the yearsended December 31, 2020, 2019 and2018.

5. OtherIncome, Net

Otherincome, netfor 2020 included interest income ($12 million),partially offset by equity losses from investments in ammoniaplants in Trinidad($2 million). Other income, netfor 2019 included interest income($26million) and net foreign currency transactiongains($2 million). Other income, netfor 2018 includedinterest income ($12 million), adownward adjustment to deferred compensation expense ($6 million) andequity income from investments in ammonia plantsinTrinidad ($2 million), partially offsetbynet foreign currencytransaction losses ($7million).

F-18 6. Income Taxes

The principal components of EOG's total netdeferred income tax liabilities at December 31, 2020 and 2019 were as follows (in thousands): 2020 2019 DeferredIncomeTax Assets (Liabilities) ForeignOil and Gas Exploration and Development CostsDeducted for TaxUnder Book Depreciation,Depletion and Amortization $25,129 $5,825 Foreign NetOperating Loss 74,280 66,675 Foreign Valuation Allowances (97,499) (70,455) Foreign Other 217 318 Total NetDeferred IncomeTax Assets $2,127 $2,363 DeferredIncomeTax (Assets) Liabilities Oiland GasExploration andDevelopment CostsDeducted for TaxOverBook Depreciation,Depletion and Amortization $5,028,010 $5,277,550 CommodityHedgingContracts 14,518 (4,699) DeferredCompensation Plans (42,594) (47,650) AccruedExpenses andLiabilities—(8,502) Equity Awards (102,944)(108,324) AlternativeMinimum TaxCredit Carryforward —(31,904) Undistributed ForeignEarnings 9,843 15,746 Other(47,506) (46,116) Total NetDeferred Income TaxLiabilities$4,859,327 $5,046,101 Total NetDeferred Income TaxLiabilities$4,857,200 $5,043,738

The components of Income (Loss) Before Income Taxesfor the years indicatedbelow were as follows(in thousands): 2020 2019 2018

UnitedStates $(756,479) $3,466,578 $4,084,156 Foreign 17,425 78,689 156,842 Total $(739,054) $3,545,267 $4,240,998

F-19 TheprincipalcomponentsofEOG's Income TaxProvision (Benefit)for the yearsindicated below were as follows (in thousands): 2020 2019 2018 Current: Federal $(107,834) $(152,258) $(303,853) State6,790 10,819 17,048 Foreign 40,248 81,426 65,615 Total (60,796) (60,013) (221,190) Deferred: Federal (153,027) 626,901 862,075 State(15,400) 32,541 43,293 Foreign (17,963) (27,784) (11,212) Total (186,390) 631,658 894,156 Other Non-Current: (1) Federal 112,704 245,125 148,992 Foreign —(6,413) — Total 112,704 238,712 148,992

Income Tax Provision (Benefit) $(134,482) $810,357 $821,958

(1)Includes changes in certain amounts that are expected to be paid or received beyond thenexttwelve months. The primary component is refundable alternative minimumtax (AMT) credits.

The differencesbetween taxes computed at theU.S.federal statutory tax rate and EOG's effective rate forthe years indicated below were as follows: 2020 2019 2018 StatutoryFederal IncomeTax Rate21.00 %21.00 %21.00 % StateIncomeTax, NetofFederal Benefit 0.92 0.97 1.12 IncomeTax Provision RelatedtoForeign Operations (0.09)0.87 0.51 IncomeTax Provision RelatedtoCanadianOperations (2.43) —— TCJA (1) ——(2.60) (2) Share-Based Compensation(2.94)0.02 (0.47) Other 1.74 —(0.18) Effective Income TaxRate 18.20 %22.86 %19.38 %

(1)The TaxCuts and Jobs Act(TCJA) wasenacted in 2017 and requiredcertain measurement-period adjustments in 2018. (2) Includes impactofutilizing certain tax net operatinglosses (NOLs) ((1.2)%), the reversal of the federal sequestration charge ((1.0)%) and other TCJAimpacts ((0.4)%).

The net effective tax rate of 18% in 2020 waslower thanthe prior yearrateof23% primarily due to taxesattributable to EOG'sforeign operationsand increasedstock-based compensationtax deficiencies.

Deferredtax assetsare recorded for certain tax benefits, includingtax NOLs and tax creditcarryforwards,provided that management assessesthe utilizationofsuchassets to be "more likely than not." Management assessesthe available positive and negativeevidence to estimate if sufficient future taxableincomewill be generated to usethe existing deferred tax assets. On the basis of thisevaluation, EOGhas recordedvaluationallowances for the portion of certain foreign and state deferredtax assets that management does notbelieve aremore likelythannot to be realized.

F-20 Theprincipal componentsofEOG's rollforwardofvaluation allowances fordeferredincome tax assets forthe years indicated below were as follows (in thousands):

2020 2019 2018

Beginning Balance$200,831 $167,142 $466,421 Increase (1) 25,573 30,673 23,062 Decrease (2) (11,343) (75) (26,219) Other (3) 3,942 3,091 (296,122) Ending Balance$219,003 $200,831 $167,142

(1)Increase in valuationallowancerelated to the generation of taxNOLs and other deferred taxassets. (2) Decrease in valuation allowance associated with adjustmentstocertain deferred tax assets andtheir related allowances. (3) Represents dispositions, revisions and/or foreign exchange rate variances and the effect of statutory income tax rate changes. The United Kingdom operations were sold in thefourthquarter of 2018.

As of December 31, 2020, EOG hadstate income tax NOLsofapproximately $1.9 billion, which, if unused, expire between2021and 2039. EOG also has CanadianNOLsof$275 million, some of whichcan be carriedforward up to 20 years. As described above,these NOLs and other less significant taxbenefitshavebeen evaluated forthe likelihood of utilization, and valuation allowances have beenestablishedfor the portion of these deferred income tax assets that do notmeetthe “more likely thannot” threshold.

The total balanceofunrecognized taxbenefits for alljurisdictionsatDecember 31, 2020,was $10million,resulting from the tax treatment of certain compensationdeductions, of whichthe full amount maypotentially have an earnings impact. During the fourth quarterof2020, EOG settleduncertaintax positions resulting from its tax treatmentofresearch and experiential expendituresrelated to certain innovationsinits horizontaldrilling and completionoperations for taxableyears 2016 and 2017. Consequently, the balance of uncertain tax positionsand earnings for the period decreased $29 million and $5 million, respectively.EOG records interest andpenalties related to unrecognizedtax benefitstoits income tax provision. No interest expense hasbeen recognizedinthe Consolidated StatementsofIncome(Loss)and Comprehensive Income(Loss) related to theremaining unrecognizedtax benefitsasthese positions willbeclaimed on amendedreturns or as self-proposed auditadjustments, which, if sustained, willresult in refunds. EOG does notanticipate thatthe amount of the unrecognized tax benefitswillchange materially during the nexttwelve months. EOG and its subsidiaries file incometax returns and are subject to taxaudits in the U.S. and various state, local and foreign jurisdictions. EOG's earliest open taxyears in itsprincipal jurisdictions are as follows: U.S. federal (2016), Canada (2016), Trinidad(2013) and China(2010).

EOG'sforeign subsidiaries' undistributed earnings are not considered to be permanently reinvested outside of the U.S. Accordingly, EOG mayberequired to accrue certain U.S. federal, state, and foreigndeferred income taxes on these undistributed earningsaswellasonany other outside basis differences related to itsinvestments in thesesubsidiaries.Asof December 31, 2020, EOG hascumulativelyrecorded $10 millionofdeferred foreignincometaxes for withholdings on its undistributed foreign earnings. Additionally, EOG'sforeign earnings maybesubject to theU.S. federal"global intangible low- taxedincome"(GILTI) inclusion. EOG records any GILTI tax as aperiod expense.

7. Employee Benefit Plans

Stock-BasedCompensation

During 2020, EOG maintained various stock-basedcompensation plans as discussed below. EOGrecognizes compensation expense on grantsofstockoptions, SARs, restricted stockand restrictedstockunits, performanceunits and grantsmadeunder theEOG Resources, Inc. EmployeeStockPurchasePlan (ESPP). Stock-based compensationexpenseis calculated based upon the grant date estimated fair value of the awards, net of forfeitures, based upon EOG's historical employeeturnoverrate. Compensation expense is amortized over the shorterofthe vestingperiod or the period from date of grant untilthe datethe employeebecomeseligible to retirewithoutcompany approval.

F-21 Stock-basedcompensation expense is included on the Consolidated StatementsofIncome(Loss) andComprehensive Income (Loss)based upon the jobfunctions of the employeesreceivingthe grants. Compensation expense related to EOG's stock-basedcompensation plans for the years endedDecember31, 2020, 2019 and 2018 wasasfollows (inmillions): 2020 2019 2018

Leaseand Well $52$ 56 $51 Gathering andProcessing Costs111 Exploration Costs212625 Generaland Administrative 72 92 78 Total$146 $175 $155

The Amendedand Restated EOG Resources, Inc.2008 Omnibus Equity Compensation Plan (2008 Plan) provides for grants of stockoptions, SARs, restricted stock andrestricted stock units,performance units,and otherstock-based awards.

The vesting schedulesfor grantsofstock options, SARs, restricted stock andrestrictedstock units,and performance unitsare generally as follows:

Grant Type Vesting Schedule StockOptions/SARs Vesting in increments of one-third on each of the first threeanniversaries, respectively, of the dateofgrant

RestrictedStock/Restricted Stock "Cliff" vesting threeyears from thedate of Units grant

Performance Units "Cliff" vesting on the February 28th following thethree-year performanceperiod andthe Compensation Committee's certification of the applicableperformance multiple

At December31, 2020, approximately 2.0 million common sharesremainedavailablefor grantunderthe 2008 Plan. EOG'spolicyistoissue shares relatedtothe 2008 Planfrompreviously authorizedunissued shares or treasury sharestothe extenttreasury sharesare available.

During 2020, 2019 and2018, EOGissuedshares in connection withstock option/SARexercises, restricted stock grants, restricted stock unit andperformanceunitreleases and ESPP purchases. Net tax deficiencies and excess taxbenefits recognized withinthe income tax provision were $(22) million, $(1) million and $20 million forthe years endedDecember31, 2020, 2019 and 2018, respectively.

StockOptions and Stock-Settled Stock AppreciationRights andEmployee StockPurchase Plan. ParticipantsinEOG's stock-basedcompensation plans (including the 2008 Plan) have beenormay be granted options to purchase shares of Common Stock. In addition,participants in EOG's stockplans (including the 2008 Plan) have been or may be grantedSARs, representing the right to receive sharesofCommon Stock based on the appreciationinthe stockpricefromthe date of granton the numberofSARs granted. Stockoptions andSARsare granted at apricenot lessthan the market price of theCommon Stock on thedate of grant. Terms for stockoptionsand SARsgranted have generally not exceeded amaximumtermofseven years. EOG'sESPP allows eligible employeestosemi-annually purchase, through payroll deductions, sharesofCommonStock at 85 percent of the fairmarketvalueatspecified dates. Contributions to the ESPPare limited to 10 percent of the employee's pay (subjecttocertain ESPP limits)during each of the two six-monthoffering periods eachyear.

F-22 Thefair valueofstock optiongrantsand SAR grantsisestimated using the Hull-White II binomialoption pricing model. Thefair valueofESPP grantsisestimated using the Black-Scholes-Mertonmodel. Stock-based compensation expense related to stockoption, SAR and ESPP grants totaled $62million, $63million and$60 million for the years ended December 31, 2020, 2019 and2018, respectively.

Weightedaverage fairvalues and valuationassumptions usedtovalue stock option, SAR andESPPgrantsfor the years endedDecember 31, 2020, 2019 and2018 were as follows: Stock Options/SARs ESPP 2020 2019 2018 2020 2019 2018

Weighted Average FairValue of Grants $11.06 $19.49 $33.46 $19.14 $22.83 $25.75 Expected Volatility44.47 %32.02 %28.23 %53.48 %34.78 %24.59 % Risk-FreeInterest Rate 0.21 %1.69 %2.68 %0.90 %2.27 %1.89 % Dividend Yield 3.27 %1.39 %0.72 %2.27 %1.04 %0.64 % Expected Life 5.2years 5.1 years5.0 years 0.5 years 0.5 years 0.5 years

Expected volatility is based on an equalweightingofhistoricalvolatility and implied volatility from traded options in EOG'sCommon Stock. Therisk-freeinterest rateisbasedupon UnitedStatesTreasury yields in effect at thetimeofgrant. The expected lifeisbased upon historicalexperience and contractualtermsofstock option, SARand ESPP grants.

The following table setsforth thestock option and SAR transactions for the yearsendedDecember 31,2020, 2019 and 2018 (stockoptions andSARs in thousands): 2020 2019 2018 Number Weighted Number Weighted Number Weighted of Stock Average of Stock Average of Stock Average Options/ Grant Options/ Grant Options/ Grant SARs Price SARs Price SARs Price

Outstanding at January 19,395 $94.53 8,310 $96.90 9,103 $83.89 Granted1,996 37.631,965 75.39 1,906 126.49 Exercised (1) (23) 69.59 (606) 61.43 (2,493) 72.21 Forfeited (1,182) 88.93 (274) 102.57 (206) 94.43 Outstanding at December 31 10,186 84.08 9,395 94.53 8,310 96.90 StockOptions/SARsExercisableat December 31 6,343 96.41 5,275 94.21 3,969 85.82

(1) The total intrinsic value of stock options/SARs exercised during the years 2020, 2019 and 2018 was $0.4 million, $14 million and $118 million, respectively. The intrinsic value is basedupon the difference between the market price of the Common Stock on the date of exercise andthe grant priceofthe stock options/SARs.

At December31, 2020, there were 9.9millionstock options/SARs vestedorexpected to vest with aweighted average grant priceof$84.76 per share, an intrinsic value of $22.5 millionand aweightedaverage remaining contractual life of 4.2 years.

F-23 Thefollowingtable summarizes certain informationfor the stock options andSARs outstanding and exercisable at December 31, 2020 (stockoptions and SARsinthousands): Stock Options/SARs Outstanding Stock Options/SARs Exercisable Weighted Weighted Average Weighted Average Weighted Range of Stock Remaining Average Aggregate Stock Remaining Average Aggregate Grant Options/ Life Grant Intrinsic Options/ Life Grant Intrinsic Prices SARs (Years) Price Value(1) SARs (Years) Price Value (1)

$34.00 to $43.99 1,974 7 $37.43 10 1 $37.44 44.00 to 74.99 872 2 69.37 846 2 69.47 75.00 to 75.99 1,863 6 75.09 636 5 75.09 76.00 to 95.99 1,242 3 94.47 1,215 3 94.63 96.00 to 101.99 2,477 3 97.95 2,457 3 97.95 102.00 to 129.99 1,758 5 126.44 1,179 5 126.37 10,186 4 84.08 $24,578 6,343 3 96.41 $124

(1) Baseduponthe difference between the closing marketpriceofthe CommonStock on thelast trading dayofthe yearand the grant price of in-the-money stock options andSARs,inthousands.

At December31, 2020, unrecognized compensation expense related to non-vested stockoption and SAR grants totaled $53 million. This unrecognizedexpense willbeamortizedonastraight-line basisoveraweightedaverage period of 2.1 years.

At the 2018 Annual MeetingofStockholders,EOG stockholders approvedanamendment andrestatement of the ESPP to (among otherchanges) increase the numberofshares availablefor grant. At December 31, 2020, approximately 1.9million shares of Common Stockremainedavailable for grant underthe ESPP. The following tablesummarizes ESPP activity for the years endedDecember31, 2020, 2019 and 2018 (inthousands, except number of participants): 2020 2019 2018

Approximate Number of Participants2,063 1,998 1,934 Shares Purchased377 224180 AggregatePurchase Price $16,103 $16,533 $14,887

Restricted Stockand Restricted StockUnits. Employeesmay be granted restricted (non-vested) stockand/or restricted stockunits without cost to them. Upon vesting of restricted stock, sharesofCommon Stockare released to theemployee. Upon vesting, restricted stockunitsare convertedintoshares of Common Stockand released to the employee.Stock-based compensation expense related to restricted stockand restrictedstock units totaled $75 million, $97 millionand $81 million for the years ended December 31, 2020, 2019 and 2018, respectively.

F-24 Thefollowing table setsforth the restricted stock and restricted stock unit transactionsfor the years ended December 31, 2020, 2019 and2018 (shares andunits in thousands): 2020 2019 2018 Weighted Weighted Weighted Numberof Average Numberof Average Number of Average Sharesand Grant Date Sharesand Grant Date Shares and Grant Date Units FairValue Units FairValue Units Fair Value

Outstanding at January 14,546 $90.16 3,792 $96.64 3,905 $88.57 Granted1,488 38.101,749 80.01 812 117.55 Released (1) (1,213) 85.92 (855) 96.93 (740) 78.16 Forfeited (79) 86.52 (140) 97.54 (185) 92.12 Outstanding at December 31 (2) 4,742 74.97 4,546 90.16 3,792 96.64

(1) The totalintrinsic value of restricted stock and restricted stock units released during the years ended December 31, 2020,2019 and 2018 was $48 million,$70 million and $84 million, respectively. The intrinsicvalue is based upon the closingpriceofEOG's common stock on the date restricted stock and restricted stock units are released. (2) The total intrinsic value of restricted stock and restricted stock units outstanding at December 31, 2020, 2019 and2018 was $236 million, $381 millionand $331million, respectively. The intrinsic value is based on the closing market price of the Common Stock on the last trading day of the year.

At December31, 2020, unrecognized compensation expense related to restrictedstock and restricted stockunits totaled $178 million.Suchunrecognized expense will be recognizedonastraight-line basisoveraweighted average periodof 1.6years.

PerformanceUnits. EOG hasgrantedperformance units(Performance Awards) to itsexecutive officers annually since2012. As more fullydiscussedinthe grant agreements, the performancemetric applicable to these performance-based grantsisEOG's total shareholder return overathree-year performance periodrelative to the totalshareholder return of a designated group of peercompanies(PerformancePeriod).Uponthe application of the performancemultiple at the completion of the PerformancePeriod, aminimum of 0% and amaximumof200% of the PerformanceAwardsgranted couldbe outstanding. The fairvalueofthe Performance Awards is estimated using aMonte Carlosimulation. Stock-based compensation expense related to thePerformance Award grantstotaled $9 million, $15 million and$14 million for the years endedDecember31, 2020, 2019 and2018, respectively.

Weightedaverage fair values and valuationassumptions used to value Performance Awards during the years ended December 31, 2020, 2019 and2018 were as follows: 2020 2019 2018

Weighted Average FairValue of Grants$42.77 $79.98 $136.74 Expected Volatility 47.27 %29.20 %29.92 % Risk-Free Interest Rate0.16 %1.51% 2.85 %

Expected volatilityisbased on the term-matched historical volatility over the simulated term, which is calculated as the time between thegrant date and theend of the PerformancePeriod. Therisk-free interest rate is derived fromthe Treasury ConstantMaturitiesyield curveonthe grant date.

F-25 Thefollowing table setsforth the PerformanceAward transactions for the yearsended December 31, 2020, 2019 and 2018 (units in thousands): 2020 2019 2018 Weighted Weighted Weighted Average Average Average Numberof Priceper Number of Priceper Numberof Priceper Units Grant Date Units GrantDate Units Grant Date

Outstanding at January 1598 $92.19 539 $101.53 502$ 90.96 Granted 172 37.44 172 75.09 113 125.73 Grantedfor PerformanceMultiple (1) 66 100.95 72 69.43 72 101.87 Released (2) (223)88.52 (185) 94.63 (148)84.43 Forfeited —————— Outstanding at December 31 (3) 613 (4) 79.10 598 92.19 539 101.53

(1) Upon completion of the Performance Period for the Performance Awards granted in 2016, 2015 and 2014, aperformance multiple of 150%, 200%and 200%, respectively, was applied to each of the grants resulting in additional grants of Performance AwardsinFebruary 2020, 2019 and 2018. (2) The total intrinsic value of Performance Awardsreleasedduring the years ended December 31, 2020, 2019 and 2018 was $13 million, $15 million and $18 million, respectively. The intrinsic valueisbased upon the closingprice of EOG's commonstockonthe date Performance Awards are released. (3) The total intrinsic value of Performance AwardsoutstandingatDecember 31, 2020, 2019 and 2018 was $31 million, $50 millionand $47 million, respectively. The intrinsic value is based on the closing market price of the Common Stock on the last trading day of the year. (4) Upon the application of the relevant performance multiple at the completionofeachofthe remainingPerformance Periods, aminimum of 77 and amaximum of 1,149 Performance Awards could be outstanding.

At December31, 2020, unrecognized compensation expense related to Performance Awards totaled $5 million. Such unrecognized expensewill be amortized on astraight-line basisover aweightedaverage period of 1.9 years.

Upon completion of the PerformancePeriodfor the PerformanceAwards grantedinSeptember 2017,aperformance multipleof125% wasappliedtothe grants resulting in an additionalgrant of 19,629 PerformanceAwards in February 2021.

Pension Plans. EOGhas adefined contribution pension planinplace for most of itsemployeesinthe United States. EOG'scontributions to the pensionplanare based on various percentagesofcompensation and, in some instances, are based upon the amount of the employees' contributions. EOG'stotal costs recognized for the plan were $46 million, $51million and $43 million for 2020, 2019 and 2018, respectively.

In addition, EOG's Trinidadiansubsidiary maintains acontributory defined benefitpension planand amatched savings plan.These pension plans are availabletomost employeesofthe Trinidadian subsidiary. EOG'scombinedcontributions to these plans were $1 million, for each of 2020, 2019 and2018, respectively.

Forthe Trinidadiandefined benefit pensionplan, the benefitobligation, fair value of plan assets and accrued benefit cost totaled $13million, $12 million and$0.1 million, respectively, at December 31,2020, and$12 million, $10 million and $0.1 million, respectively, at December31, 2019.

Postretirement HealthCare. EOG has postretirement medical anddentalbenefits in placefor eligible United States and Trinidademployees andtheireligible dependents, the costs of whichare not material.

F-26 8. Commitments and Contingencies

Letters of Credit and Guarantees. At December 31,2020and 2019, respectively, EOGhad standbyletters of credit and guarantees outstanding totaling $854 million and $902 million, primarily representing guarantees of payment or performanceobligations on behalfofsubsidiaries. As of February 18, 2021, EOG had receivednodemands for payment under these guarantees.

Minimum Commitments. At December 31, 2020, total minimumcommitments from purchase and service obligations and transportation and storage servicecommitments not qualifying as leases,based on current transportationand storage rates and the foreign currencyexchange rates usedtoconvert Canadian dollars intoUnited Statesdollars at December 31, 2020, were as follows (in millions): TotalMinimum Commitments

2021 $1,393 2022 1,263 2023 1,064 2024 790 2025 649 2026 and beyond 2,764 $7,923

Contingencies. There are currently various suitsand claims pending against EOG thathave arisen in the ordinary course of EOG's business,including contractdisputes,personal injuryand propertydamage claims and title disputes. While the ultimateoutcomeand impact on EOG cannot be predicted,management believes thatthe resolutionofthese suitsand claims willnot,individuallyorinthe aggregate,have amaterial adverse effect on EOG's consolidatedfinancial position, results of operations or cash flow. EOGrecords reservesfor contingencieswhen information available indicates thatalossisprobable andthe amount of the loss canbereasonablyestimated.

9. NetIncome (Loss) PerShare

Thefollowing table sets forththe computation of NetIncome (Loss) Per Share forthe yearsended December 31, 2020, 2019 and 2018 (in thousands, except pershare data): 2020 2019 2018 Numerator forBasic andDiluted Earnings per Share - NetIncome(Loss)$(604,572) $2,734,910 $3,419,040 Denominator for BasicEarnings per Share- Weighted Average Shares 578,949 577,670 576,578 PotentialDilutive CommonShares - Stock Options/SARs—258 1,137 RestrictedStock/Unitsand PerformanceUnits —2,849 2,726 Denominator for Diluted Earnings per Share - AdjustedDiluted Weighted Average Shares578,949 580,777 580,441 NetIncome (Loss) PerShare Basic$(1.04) $4.73$ 5.93 Diluted$(1.04) $4.71$ 5.89

The diluted earnings per share calculationexcludesstockoptions, SARs, restricted stock, restricted stockunits, performanceunitsand ESPP grantsthatwereanti-dilutive.Sharesunderlying the excludedstock options, SARsand ESPP grantswere9.6 million, 6.1 million and 0.6 million for the years ended December31, 2020, 2019 and2018, respectively. Shares underlying the excludedrestricted stock, restricted stockunitand performanceunitgrantswere5.0 million shares for the yearendedDecember31, 2020.

F-27 10. SupplementalCash Flow Information

Net cash paid (received) for interest andincometaxes was as followsfor the yearsended December31, 2020, 2019 and 2018 (inthousands): 2020 2019 2018

Interest,Net of Capitalized Interest $205,447 $186,546 $243,279 Income Taxes, NetofRefunds Received $(205,795) $(291,849) $75,634

EOG'saccrued capitalexpendituresatDecember 31,2020, 2019 and 2018 were $414 million, $612 million and $592 million, respectively.

Non-cash investing activities forthe yearendedDecember31, 2020, includedadditions of $212 million to EOG's oil and gas properties as aresultofpropertyexchanges and an addition of $174 milliontoEOG's other property, plant and equipment made in connection with finance leasetransactionsfor storage facilities.

Non-cash investing activities forthe yearendedDecember31, 2019, includedadditions of $150 million to EOG's oil and gaspropertiesasaresult of property exchanges.

Non-cash investing activities forthe yearendedDecember31, 2018, includedadditions of $362 million to EOG's oil and gasproperties as aresult of property exchanges and an addition of $49 million to EOG's otherproperty, plant and equipment primarily in connection withafinancelease transaction in the Permian Basin.

Cash paid for leasesfor the years ended December 31, 2020 and 2019, is disclosed in Note 18.

11. Business Segment Information

EOG'soperations are allcrude oil,NGLs and natural gasexploration and production-related. The Segment Reporting Topicofthe ASCestablishes standards for reporting information about operating segments in annualfinancial statements. Operating segmentsare definedascomponentsofanenterprise about whichseparatefinancial information is availableand evaluatedregularly by the chiefoperating decision maker, or decision-making group, in deciding how to allocate resources and in assessing performance. EOG'schief operating decision-making process is informal andinvolves the Chairman of the Board and Chief Executive Officerand otherkey officers. This group routinelyreviews and makesoperating decisions related to significant issues associatedwith each of EOG's major producingareas in the United States, Trinidadand China and its exploration program in the Sultanate of Oman (Oman). Forsegment reportingpurposes,the chiefoperating decision makers considerthe major UnitedStates producingareastobeone operating segment.

F-28 Financial informationbyreportable segmentispresented below as of and for the years endedDecember 31, 2020, 2019 and 2018 (inthousands):

United Other StatesTrinidad International (1) Total 2020 Crude Oiland Condensate $5,773,582 $10,723 $1,304 $5,785,609 NaturalGas Liquids 667,514 ——667,514 NaturalGas 614,002 168,967 54,164 837,133 Gains on Mark-to-Market Commodity Derivative Contracts 1,144,737 ——1,144,737 Gathering, Processing andMarketing 2,581,4931,491 —2,582,984 Gains (Losses) on AssetDispositions, Net (47,018) (44) 179 (46,883) Other, Net 60,989 (35) —60,954 Operating Revenues andOther (2) 10,795,299 181,102 55,647 11,032,048 Depreciation, Depletion and Amortization 3,323,800 60,629 15,924 3,400,353 (3) Operating Income (Loss) (545,566) 74,801 (73,251) (544,016) Interest Income 10,783 922 34 11,739 Other Income (Expense) 153 (2,129) 465 (1,511) NetInterest Expense 205,266 ——205,266 Income(Loss) Before IncomeTaxes (739,896) 73,594 (72,752) (739,054) IncomeTax Provision (Benefit) (156,834) 14,568 7,784 (134,482) Additions to Oiland Gas Properties,Excluding Dry Hole Costs 3,316,724 83,173 41,961 3,441,858 Total Property, Plant andEquipment, Net 28,283,027 210,278 105,322 28,598,627 Total Assets 35,047,485 546,120 210,996 35,804,601 2019 Crude Oiland Condensate $9,599,125 $11,138 $2,269 $9,612,532 NaturalGas Liquids 784,818 ——784,818 NaturalGas 866,911258,819 58,365 1,184,095 Gains on Mark-to-Market Commodity Derivative Contracts 180,275 ——180,275 Gathering, Processing andMarketing 5,355,4634,819 —5,360,282 Gains (Losses) on Asset Dispositions, Net 131,446 (3,688) (4,145) 123,613 Other, Net134,325 18 15 134,358 Operating Revenues andOther (4) 17,052,363 271,106 56,504 17,379,973 Depreciation, Depletion and Amortization 3,652,294 79,389 18,021 3,749,704 Operating Income (Loss) 3,618,907 112,790 (32,686) 3,699,011 Interest Income22,122 3,686 218 26,026 Other Income 3,235 727 1,397 5,359 NetInterest Expense 192,587 —(7,458) 185,129 Income(Loss) Before IncomeTaxes 3,451,677 117,203 (23,613) 3,545,267 IncomeTax Provision 760,881 40,901 8,575 810,357 Additions to Oiland Gas Properties, Excluding Dry Hole Costs 6,208,394 53,325 12,233 6,273,952 Total Property, Plant andEquipment, Net30,101,857 184,606 78,132 30,364,595 Total Assets36,274,942 705,747 143,919 37,124,608

F-29 United Other StatesTrinidad International (1) Total 2018 Crude Oiland Condensate $9,390,244 $17,059 $110,137 $9,517,440 NaturalGas Liquids 1,127,510 ——1,127,510 NaturalGas 970,866285,053 45,618 1,301,537 Loses on Mark-to-Market Commodity Derivative Contracts (165,640) ——(165,640) Gathering, Processing andMarketing 5,227,0513,304 —5,230,355 Gains on Asset Dispositions, Net 154,852 4,493 15,217 174,562 Other, Net89,708(49)(24)89,635 Operating Revenues andOther (5) 16,794,591 309,860 170,948 17,275,399 Depreciation, Depletion and Amortization 3,296,499 91,971 46,938 3,435,408 Operating Income (Loss) 4,334,364 147,240 (12,258) 4,469,346 Interest Income9,326 1,612608 11,546 Other Income (Expense) 9,580 2,436 (6,858) 5,158 NetInterest Expense 253,352 —(8,300) 245,052 Income(Loss) Before IncomeTaxes 4,099,918 151,288 (10,208) 4,240,998 IncomeTax Provision 765,986 54,272 1,700 821,958 Additions to Oiland Gas Properties, Excluding Dry Hole Costs 6,155,874 1,618 37,838 6,195,330 Total Property, Plant andEquipment, Net27,786,086 210,183 79,250 28,075,519 Total Assets33,178,733 629,633 126,108 33,934,474

(1) OtherInternational primarily consistsofEOG's United Kingdom, China and Canadaoperations. EOGbegan an exploration program in Oman in the third quarter of 2020. The UnitedKingdom operationsweresold in thefourthquarter of 2018. (2) EOG had sales activity withthree significant purchasers in 2020, each totaling $1.1 billion of consolidatedOperating Revenues and Other in the United Statessegment. (3) EOG recordedpretax impairment charges of $1,570 millionin2020for proved oil and gas properties, leasehold costs and other assets due to the decline in commodity prices and revisions of asset retirement obligations for certain properties in the UnitedStatessegment. In addition,EOG recordedpretax impairment charges of $228million in 2020 for owned and leasedsandand crude-by-rail assets, also in the United States segment.EOG recorded pretax impairment charges of $81 millionin2020 for proved oil and gas properties and firm commitment contracts related to its decision to exit the Horn River Basin in British Columbia,Canada, in the OtherInternational segment. See Notes 13 and 14. (4) EOG had sales activity with two significant purchasers in 2019, one totaling$2.4 billion and the othertotaling$2.2billionof consolidated Operating Revenues and Other in the United Statessegment. (5) EOG had sales activity with two significant purchasers in 2018, one totaling$2.6 billion and the othertotaling$2.3billionof consolidated Operating Revenues and Other in the United Statessegment.

F-30 12. Risk Management Activities

CommodityPrice Risks. EOG engagesinprice risk management activitiesfromtime to time. These activities are intendedtomanage EOG'sexposure to fluctuations in commodity pricesfor crude oil,NGLsand natural gas. EOG utilizes financial commodityderivative instruments, primarily priceswap, option, swaption, collarand basisswapcontracts, as ameans to manage thisprice risk.

During 2020, 2019 and 2018, EOG elected nottodesignateany of its financial commodityderivativecontracts as accounting hedgesand, accordingly, accountedfor these financial commodity derivativecontracts using the mark-to-market accounting method. Underthis accounting method, changes in thefair value of outstanding financial instruments are recognized as gains or losses in the period of change andare recorded as Gains (Losses) on Mark-to-MarketCommodity Derivative Contractsonthe ConsolidatedStatements of Income (Loss)and Comprehensive Income (Loss).The related cash flow impactisreflectedinCashFlows from Operating Activities. During 2020, 2019 and 2018, EOGrecognizednet gains (losses)onthe mark-to-market of financial commodityderivative contracts of $1,145 million, $180 million and$(166)million, respectively,which includedcashreceived from (payments for) settlements of crude oil, NGLs and natural gasderivative contracts of $1,071 million, $231 million and$(259)million, respectively.

Crude OilDerivative Contracts. Prices receivedbyEOG forits crudeoil production generally vary from U.S. New York Mercantile Exchange (NYMEX) West TexasIntermediate (WTI)prices duetoadjustments for delivery location(basis) and otherfactors. EOG has enteredintocrude oil basis swap contracts in order to fixthe differentialbetween Intercontinental Exchange (ICE) Brent pricing and pricing in Cushing, Oklahoma(ICEBrent Differential). Presented below is acomprehensive summary of EOG's ICE Brent Differential basis swap contracts as of December 31, 2020. The weighted average price differential expressedindollarsper barrel($/Bbl)representsthe amount of additiontoCushing, Oklahoma, pricesfor the notional volumes expressedinbarrels perday (Bbld) coveredbythe basisswap contracts.

ICE Brent Differential BasisSwap Contracts Weighted Average Price Volume Differential (Bbld) ($/Bbl) 2020 May2020 (closed) 10,000 $4.92

EOG has also enteredinto crude oil basis swap contractsinorder to fix the differential between pricing in Houston, Texas,and Cushing, Oklahoma (Houston Differential). Presentedbelow is acomprehensive summary of EOG's Houston Differentialbasisswapcontracts as of December 31, 2020. The weighted average price differentialexpressedin$/Bbl represents theamountofadditiontoCushing, Oklahoma, pricesfor the notionalvolumes expressed in Bbld covered by the basis swap contracts.

HoustonDifferential BasisSwap Contracts Weighted Average Price Volume Differential (Bbld) ($/Bbl) 2020 May2020 (closed) 10,000 $1.55

F-31 EOGhas also enteredinto crude oilswaps in order to fixthe differential in pricing betweenthe NYMEXcalendar monthaverage andthe physical crude oil deliverymonth(RollDifferential).Presented below is acomprehensive summary of EOG'sRollDifferential basis swap contracts as of December 31, 2020. The weighted average pricedifferential expressed in $/ Bbl represents the amount of netaddition (reduction) to delivery month prices for the notionalvolumes expressed in Bbld covered by the swapcontracts.

Roll Differential BasisSwap Contracts Weighted Average Price Volume Differential (Bbld) ($/Bbl) 2020 February 1, 2020 throughJune 30, 2020 (closed) 10,000 $0.70 July1,2020 through September30, 2020 (closed) 88,000 (1.16) October1,2020 through December31, 2020 (closed) 66,000 (1.16)

2021 February 1, 2021 throughDecember31, 2021 25,000 $0.10

2022 January 1, 2022 through December31, 2022 50,000 $0.11

In May 2020, EOG enteredinto crude oilRollDifferential basis swap contractsfor the period from July 1, 2020 through September 30, 2020, withnotional volumes of 22,000 Bbldataweighted average pricedifferential of $(0.43) per Bbl, and for the period from October 1, 2020 through December 31,2020, withnotional volumes of 44,000 Bbldataweighted average pricedifferential of $(0.73) per Bbl.These contracts partially offset certain outstandingRollDifferential basisswap contracts forthe sametimeperiods and volumesataweighted average pricedifferentialof$(1.16) per Bbl. EOG paidnet cash of $3.2 million for the settlement of these contracts. Theoffsetting contracts were excluded from the above table.

Presentedbelow is acomprehensive summary of EOG'scrude oil NYMEXWTI price swap contractsasofDecember 31,2020, withnotional volumesexpressed in Bbld andpricesexpressedin$/Bbl.

Crude OilNYMEX WTI PriceSwap Contracts Weighted Volume Average Price (Bbld) ($/Bbl) 2020 January 1, 2020 through March 31, 2020 (closed) 200,000 $59.33 April 1, 2020 through May31, 2020 (closed) 265,000 51.36

In April andMay 2020, EOG entered intocrude oil NYMEXWTI priceswapcontracts forthe period from June1, 2020 through June 30, 2020, withnotionalvolumes of 265,000 Bbld at aweighted average priceof$33.80 per Bbl, for the period from July1,2020 through July 31, 2020, withnotionalvolumes of 254,000 Bbldataweighted average priceof$33.75 per Bbl, for the period from August 1, 2020 through September 30, 2020, with notionalvolumes of 154,000 Bbld at aweighted averageprice of $34.18 per Bbland for the periodfromOctober 1, 2020 through December 31, 2020, withnotional volumesof 47,000 Bbldataweighted average priceof$30.04 per Bbl.These contractsoffset theremainingcrude oil NYMEXWTI price swap contractsfor the sametimeperiods and volumesataweighted average priceof$51.36per Bbl for the periodfromJune 1, 2020 through June 30,2020, $42.36 per Bblfor the period from July1,2020through July31, 2020, $50.42 per Bbl for the period from August 1, 2020 through September 30,2020and $31.00 per Bbl for the periodfromOctober1,2020 through December 31, 2020. EOG received net cash of $362.6 million through December31, 2020, for the settlement of certainof these contracts, and expectstoreceive netcashof$1.4million during January 2021 for the settlementofthe remaining contracts. The offsetting contractswereexcludedfrom the abovetable.

F-32 Presentedbelowisacomprehensive summary of EOG'scrude oil ICE Brent price swap contractsasofDecember31, 2020,withnotional volumes expressedinBbld andpricesexpressedin$/Bbl.

Crude OilICE BrentPrice Swap Contracts Weighted Volume Average Price (Bbld) ($/Bbl) 2020 April 2020 (closed) 75,000 $25.66 May2020 (closed) 35,000 26.53

NGLs Derivative Contracts. Presented below is acomprehensive summary of EOG's Mont Belvieu propane (non- TET) price swapcontractsasofDecember 31, 2020, withnotionalvolumesexpressedinBbldand prices expressedin$/Bbl.

MontBelvieu Propane PriceSwap Contracts Weighted Volume Average Price (Bbld) ($/Bbl) 2020 January 1, 2020 through February 29, 2020 (closed) 4,000 $21.34 March1,2020 through April 30, 2020 (closed) 25,000 17.92

In April andMay 2020, EOG enteredintoMont Belvieu propane priceswapcontracts for the period from May 1, 2020 through December31, 2020, withnotionalvolumesof25,000 Bbldataweighted average priceof$16.41 perBbl. These contracts offset the remaining Mont Belvieupropane priceswapcontracts for the same time period withnotionalvolumes of 25,000 Bbldataweightedaverage priceof$17.92 per Bbl. EOGreceivednet cash of $8.0 millionthrough December 31, 2020, for the settlement of certain of these contracts, and expectstoreceive net cash of $1.2 millionduring January 2021 for the settlementofthe remaining contracts. The offsetting contractswereexcludedfrom the above table.

Natural Gas DerivativeContracts. Presentedbelow is acomprehensive summary of EOG's naturalgas NYMEX Henry Hub price swap contractsasofDecember31, 2020, withnotionalvolumessold(purchased) expressedinmillionBritish thermalunits (MMBtu) perday (MMBtud) and prices expressedindollarsper MMBtu ($/MMBtu).

Natural GasNYMEX HenryHub Price Swap Contracts Weighted Volume Average Price (MMBtud) ($/MMBtu) 2021 April 1, 2021 through December31, 2021 500,000 $2.99

2022 January 1, 2022 through December31, 2022 20,000 $2.75

In December2020, EOG enteredinto natural gasNYMEX Henry Hub price swap contracts for the period from January 1, 2021 through March 31, 2021, with notionalvolumes of 500,000MMBtud at aweighted average priceof$2.43 per MMBtu. These contractsoffsetthe remaining natural gasNYMEX HenryHub price swap contractsfor the sametimeperiod with notional volumesof500,000 MMBtud at aweightedaverage priceof$2.99 perMMBtu. EOG expectstoreceive net cash of $25.2 million during 2021 for the settlement of these contracts. Theoffsetting contracts were excluded from theabove table.

F-33 EOGhas enteredinto natural gas collarcontracts, which establish ceiling andfloorpricesfor the saleofnotional volumes of natural gasasspecified in thecollar contracts. The collarsrequire thatEOG pay the differencebetween theceiling price and the NYMEX Henry Hub naturalgas price forthe contract month(Henry Hub Index Price) in the event the Henry Hub Index Priceisabove the ceilingprice.The collars grant EOGthe right to receive the difference between the floorprice and the Henry Hub Index Price in theevent the HenryHub Index Price is below the floor price.InMarch 2020,EOG executed theearly terminationprovision granting EOG the right to terminatecertain 2020 natural gas collar contracts withnotionalvolumes of 250,000 MMBtud at aweighted average ceilingprice of $2.50 per MMBtu and aweightedaverage floor priceof$2.00 per MMBtu for the period from April 1, 2020 through July31, 2020. EOG received net cash of $7.8 millionfor the settlement of these contracts. Presented below is acomprehensive summary of EOG's natural gascollar contracts as of December31, 2020, withnotional volumesexpressed in MMBtud andpricesexpressedin$/MMBtu.

Natural GasCollarContracts WeightedAverage Price ($/MMBtu) Volume (MMBtud) Ceiling Price FloorPrice 2020 April 1, 2020 through July31, 2020 (closed) 250,000 $2.50 $2.00

In April2020, EOG enteredinto natural gascollar contracts for the period from August 1, 2020 through October31, 2020, withnotionalvolumes of 250,000 MMBtud at aceilingprice of $2.50 per MMBtuand afloor priceof$2.00 per MMBtu. These contractsoffset theremaining naturalgas collar contracts forthe sametimeperiod withnotional volumes of 250,000 MMBtud at aceilingprice of $2.50 per MMBtu and afloorprice of $2.00 per MMBtu. EOGreceived netcashof$1.1 million for the settlement of these contracts. The offsettingcontracts were excluded from the above table.

Prices received by EOG for its natural gasproduction generally vary from NYMEXHenry Hubpricesdue to adjustmentsfor delivery location (basis) and otherfactors. EOG hasentered intonatural gasbasis swap contracts in ordertofix the differentialbetween pricing in the Rocky Mountain areaand NYMEXHenry Hubprices(Rockies Differential). Presented below is acomprehensive summary of EOG's Rockies Differentialbasis swap contracts as of December31, 2020. The weightedaverage pricedifferentialexpressedin$/MMBtu represents the amount of reduction to NYMEXHenry Hub pricesfor the notional volumesexpressedinMMBtud covered by the basisswap contracts.

RockiesDifferential BasisSwap Contracts Weighted Average Price Volume Differential (MMBtud) ($/MMBtu) 2020 January 1, 2020 through December 31, 2020 (closed) 30,000 $0.55

EOG has also enteredinto natural gasbasis swapcontracts in order to fixthe differentialbetween pricing at the Houston ShipChannel(HSC) and NYMEX Henry Hub prices(HSC Differential).InMarch 2020,EOG executed the early termination provision granting EOG the right to terminate certain 2020 HSC Differentialbasis swaps withnotional volumesof 60,000 MMBtud at aweightedaverage pricedifferential of $0.05per MMBtu for the period from April 1, 2020 through December 31, 2020. EOGpaid net cash of $0.4 million for the settlementofthese contracts. Presented below is a comprehensive summary of EOG's HSC Differentialbasis swap contracts as of December 31, 2020. The weightedaverage pricedifferentialexpressed in $/MMBtu represents the amount of reductiontoNYMEX Henry Hub pricesfor the notional volumes expressedinMMBtud covered by thebasisswap contracts.

HSCDifferential Basis Swap Contracts Weighted Average Price Volume Differential (MMBtud) ($/MMBtu) 2020 January 1, 2020 through December 31, 2020 (closed) 60,000 $0.05

F-34 EOGhas also enteredinto naturalgas basisswapcontracts in order to fix the differentialbetween pricing at the Waha Hub in WestTexas and NYMEXHenry Hubprices(WahaDifferential).Presentedbelowisacomprehensive summary of EOG'sWahaDifferential basisswap contractsasofDecember31, 2020. The weighted average pricedifferentialexpressed in $/MMBturepresentsthe amount of reduction to NYMEXHenry Hub pricesfor the notionalvolumes expressed in MMBtud covered by the basisswapcontracts.

Waha Differential BasisSwap Contracts Weighted Average Price Volume Differential (MMBtud) ($/MMBtu) 2020 January 1, 2020 through April30, 2020 (closed) 50,000 $1.40

In April 2020, EOG entered intoWahaDifferentialbasis swap contracts forthe periodfromMay 1, 2020 through December 31, 2020, withnotional volumesof50,000 MMBtud at aweighted averagepricedifferentialof$0.43 per MMBtu. These contracts offset theremaining WahaDifferential basis swap contracts forthe sametimeperiodwithnotional volumesof 50,000 MMBtud at aweightedaverage pricedifferentialof$1.40 per MMBtu. EOG paidnet cash of $11.9 million forthe settlementofthese contracts. The offsettingcontractswereexcludedfromthe abovetable.

CommodityDerivatives Location on BalanceSheet. Thefollowing table sets forth the amounts andclassification of EOG'soutstanding derivative financial instrumentsatDecember 31, 2020 and2019, respectively. Certainamountsmay be presented on anet basis on the consolidated financial statements when such amountsare with the same counterpartyand subject to amasternetting arrangement (in thousands): FairValue at December31, Description Location on BalanceSheet 2020 2019 AssetDerivatives Crude oil,NGLsand natural gas derivative contracts - Current portion Assets from PriceRisk Management Activities (1) $64,559 $1,299 Noncurrent portion OtherAssets 1,063 — Liability Derivatives Crude oil, NGLsand natural gas derivative contracts - Currentportion Liabilities from PriceRisk Management Activities (2) $—$20,194 Noncurrent Portion OtherLiabilities455 —

(1)The current portion of Assets from PriceRisk Management Activitiesconsistsofgross assets of $3 million, partiallyoffset by gross liabilities of $2 million, at December 31,2019. (2) The currentportion of Liabilitiesfrom PriceRisk Management Activitiesconsists of gross liabilities of $23 million, partiallyoffset by gross assets of $3 million at December 31, 2019.

F-35 Credit Risk. Notionalcontract amounts are used to express the magnitudeofafinancial derivative. Theamounts potentially subject to credit risk,inthe eventofnonperformancebythe counterparties, are equaltothe fairvalue of such contracts (see Note 13). EOG evaluatesits exposure to significant counterpartiesonanongoing basis, includingthose arising from physicaland financialtransactions. In some instances,EOG renegotiatespayment terms and/or requirescollateral, parent guarantees or lettersofcredittominimizecredit risk.

At December 31, 2020, EOG's netaccountsreceivablebalance related to United States hydrocarbon sales included two receivable balances,eachofwhichaccounted for more than 10% of the total balance. Thereceivables weredue from two petroleum refinery companies. The related amounts were collected during early2021. At December31, 2019, EOG's net accountsreceivable balance related to United States hydrocarbon sales included three receivable balances, each of which accounted formore than10% of the total balance. The receivables were duefromthree petroleum refinery companies. The related amountswere collected duringearly 2020.

In 2020 and 2019, allnatural gas from EOG'sTrinidadoperations was sold to the National GasCompany of Trinidad and Tobago Limited and itssubsidiary. In 2020 and 2019, allcrude oiland condensate from EOG's Trinidadoperations was sold to Heritage Petroleum Company Limited. In 2020 and 2019, allnatural gas from EOG'sChina operations was soldto Petrochina Company Limited.

All of EOG's derivative instrumentsare covered by International Swap Dealers Association MasterAgreements (ISDAs) withcounterparties. TheISDAs maycontainprovisions thatrequire EOG, if it is theparty in anet liability position,to post collateral when the amount of the netliability exceeds the threshold levelspecified for EOG's then-current credit ratings. In addition, the ISDAs mayalso providethat as aresultofcertain circumstances, including certain eventsthatcause EOG's credit ratingstobecomematerially weaker thanits then-current ratings,the counterparty mayrequire alloutstanding derivatives under the ISDA to be settled immediately. SeeNote 13 for the aggregate fair valueofall derivative instruments thatwere in a netasset position at December 31, 2020 and anet liability positionatDecember31, 2019. EOGhad no collateral postedand held no collateral at December 31, 2020 and2019.

Substantially all of EOG's accounts receivableatDecember 31,2020and 2019 resulted from hydrocarbon salesand/or joint interest billings to third-partycompanies, includingforeign state-owned entitiesinthe oiland gas industry. This concentration of customers and joint interest owners mayimpactEOG's overall credit risk,eitherpositively or negatively, in that these entities maybesimilarlyaffected by changes in economic or otherconditions.Indetermining whether or not to require collateral or othercredit enhancementsfromacustomer, EOG typically analyzes the entity'snet worth, cash flows, earnings and credit ratings.Receivables are generally not collateralized. During the three-year period endedDecember 31, 2020, credit lossesincurred on receivablesbyEOG have been immaterial.

13. FairValue Measurements

Certain of EOG's financialand nonfinancial assetsand liabilitiesare reported at fair valueonthe ConsolidatedBalance Sheets. An establishedfairvalue hierarchy prioritizesthe relativereliability of inputsusedinfair value measurements.The hierarchy giveshighest priority to Level 1inputs thatrepresentunadjusted quotedmarketpricesinactivemarkets foridentical assets andliabilitiesthatthe reporting entityhas the ability to access at the measurementdate. Level2inputsare directly or indirectly observable inputsother thanquotedpricesincludedwithin Level 1. Level3inputsare unobservable inputsand have the lowest priorityinthe hierarchy. EOGgives consideration to the creditrisk of itscounterparties,aswell as its own credit risk, whenmeasuring financial assets andliabilities at fair value.

F-36 RecurringFairValue Measurements. The following table providesfairvalue measurement information within the fair value hierarchy for certainofEOG's financial assets and liabilitiescarried at fair valueonarecurring basisatDecember 31, 2020 and 2019. Amounts shown in thousands. FairValue Measurements Using: Quoted Significant Prices in Other Significant Active Observable Unobservable Markets Inputs Inputs (Level 1) (Level2) (Level 3) Total At December31, 2020 Financial Assets (1): Natural Gas Swaps $—$66,064 $—$66,064 Financial Liabilities (2): Crude Oil Roll Differential Swaps—897 —897

At December31, 2019 Financial Assets (1): Natural Gas Liquids Swaps $—$3,401 $—$3,401 Natural Gas Basis Swaps —970 —970 FinancialLiabilities (2): Crude Oil Swaps —23,266 —23,266

(1)$65 million and$1million are included in "Current Assets -Assetsfrom Price Risk Management Activities" at December 31, 2020and 2019, respectively, on the Consolidated Balance Sheets. $1 million is includedin"OtherAssets" at December 31, 2020, on the Consolidated Balance Sheets. (2) $1 million is includedin"Other Liabilities" at December 31, 2020, on the Consolidated BalanceSheets. $20 million is included in "Current Liabilities -Liabilities fromPrice Risk Management Activities" at December31, 2019 on the Consolidated Balance Sheets.

The estimated fairvalueofcrude oil, NGLs and natural gasderivative contracts(including options/collars) was based upon forward commodity pricecurves basedonquoted marketprices. Commodity derivative contractswerevalued by utilizing an independent third-party derivative valuation providerwho usesvarious types of valuation models, as applicable.

Non-Recurring FairValue Measurements. The initial measurement of assetretirementobligations at fair valueis calculated using discountedcashflowtechniquesand based on internalestimates of future retirement costs associated with property, plant andequipment. Significant Level3inputs used in the calculationofasset retirementobligations include plugging costsand reserve lives. AreconciliationofEOG's asset retirement obligations is presented in Note 15.

Whencircumstancesindicate thatprovedoil and gas propertiesmay be impaired,EOG compares expected undiscountedfuture cash flows at adepreciation,depletion andamortization group level to the unamortized capitalizedcostof the asset.Ifthe expected undiscountedfuture cash flows, based on EOG's estimateof(and assumptions regarding) significant Level 3inputs, includingfuture crude oil, NGLs and natural gasprices, operating costs, development expenditures, anticipated production from proved reservesand otherrelevant data, are lowerthanthe unamortizedcapitalized cost, thecapitalized costis reduced to fairvalue. Fair valueisgenerally calculated usingthe Income Approachdescribedinthe Fair Value Measurement Topicofthe ASC.Incertain instances, EOG utilizes accepted offers from third-party purchasers as the basisfor determining fair value.

During 2020, due to thedeclineincommodity prices and revisions of asset retirementobligations for certain properties,provedoil and gas propertieswithacarrying amount of $1,587 million were writtendown to their fairvalueof$319 million, resulting in pretaximpairment charges of $1,268 million. In addition,EOG recordedpretaximpairment charges in 2020 of $72 million for acommodityprice-relatedwrite-down of otherassets.

During 2019, proved oil and gasproperties; other property, plant and equipment; andother assetswithacarrying amount of $998 million were writtendown to their fairvalueof$701 million, resultinginpretax impairment charges of $297 million. Included in the$297 millionpretaximpairmentchargesare $152 million of impairments of proved oil and gas properties forwhich EOGutilized an accepted offer from athird-party purchaser as the basis for determining fair value.In addition, EOG recorded pretax impairment charges in 2019 of $90million for acommodity price-related write-down of other assets.

F-37 EOGutilized average prices per acre from comparable market transactions and estimated discountedcashflows as the basisfor determining the fair value of unprovedand provedproperties,respectively, receivedinnon-cashpropertyexchanges. See Note 10.

FairValue of Debt. At December 31,2020and 2019, respectively, EOG had outstanding $5,640 million and $5,140 million aggregateprincipal amount of seniornotes, whichhad estimatedfairvaluesofapproximately$6,505 million and $5,452 million, respectively. Theestimated fair value of debt wasbased upon quoted market pricesand,where suchpriceswerenot available,otherobservable (Level 2) inputsregarding interest rates available to EOGatyear-end.

14. Impairment Expense

Impairment expense wasasfollows for theyears endedDecember 31,2020, 2019 and2018(in thousands):

2020 2019 2018

Provedproperties (1) $1,268,073 $206,469 $120,859 Unprovedproperties (2) 472,143 220,444 173,383 Other assets (3) 299,851 90,983 48,732 Inventories——4,047 Firm commitment contracts (4) 59,713 —— Total $2,099,780 $517,896 $347,021

(1)Impairments to proved oil and gas properties in 2020 includedlegacyand non-core natural gas and crude oil and combo plays. Impairmentstoproved oil and gasproperties in 2019 and 2018 includeddomestic legacy naturalgas assets. SeeNotes 1and 13. (2) Unprovedproperties withacquisition costs that are not individually significant are aggregated,and theportionofsuchcostsestimatedto be nonproductiveisamortized over the remaining lease term. Unproved properties withindividuallysignificant acquisition costs are reviewed individuallyfor impairment. Impairmentsofunproved oil andgas propertiesincluded charges of $252 millionin2020 for certain leasehold costs that arenolonger expected to be developed before expiration. See Note1. (3) Includes impairment charges for owned and leased sand and crude-by-rail assets of $228 millionin2020 (see Note 18) and acommodity price-relatedwrite-down of other assetsof$72 million, $90 millionand $49 millionin2020, 2019 and2018, respectively (seeNote 13). (4)Includesimpairment charges of $60 million in 2020 for firm commitment contracts relatedtoits decision to exit the Horn RiverBasin in British Columbia,Canada.

15. Asset Retirement Obligations

The following table presents the reconciliationofthe beginning andending aggregate carrying amountsofshort-term and long-term legal obligations associatedwiththe retirement of property, plant and equipment for the years ended December 31, 2020 and2019 (in thousands): 2020 2019

Carrying Amount at Beginning of Period $1,110,710 $954,377 Liabilities Incurred57,47798,874 Liabilities Settled (1) (54,027) (58,673) Accretion 47,083 43,462 Revisions 53,888 72,425 Foreign Currency Translations 1,407 245 Carrying Amount at EndofPeriod $1,216,538 $1,110,710

Current Portion $49,548 $37,127 Noncurrent Portion $1,166,990 $1,073,583

(1) Includes settlements related to asset sales.

F-38 Thecurrent and noncurrent portionsofEOG's assetretirement obligations areincludedinCurrent Liabilities-Other andOther Liabilities, respectively, on the Consolidated Balance Sheets.

16. ExploratoryWellCosts

EOG'snet changesincapitalized exploratory wellcostsfor the yearsendedDecember 31,2020, 2019 and 2018 are presentedbelow (inthousands): 2020 2019 2018

BalanceatJanuary 1$25,897 $4,121 $2,167 Additions Pendingthe Determination of ProvedReserves107,852 83,175 10,304 Reclassifications to Proved Properties(81,071) (39,325) (7,917) Costs ChargedtoExpense (1) (23,822) (22,074) (433) BalanceatDecember31$28,856 $25,897 $4,121

(1)Includes capitalized exploratory well costs charged to eitherdry hole costs or impairments.

2020 2019 2018

Capitalized exploratory well coststhat have beencapitalized for aperiod of one year or less $26,408 $25,897 $4,121 Capitalizedexploratory well coststhat have beencapitalized for aperiod greaterthanone year (1) 2,448 —— Balance at December31$28,856 $25,897 $4,121

Number of exploratory wells thathave been capitalizedfor aperiod greaterthan one year1——

(1) Consistsofcosts related to aproject in the United StatesatDecember 31, 2020.

F-39 17. Acquisitions and Divestitures

During 2020, EOG paidcashfor propertyacquisitions of $82 million in the United Statesand $38 millioninOther International,primarilyinOman. Additionally during 2020,EOG recognized net lossesonassetdispositions of $47 million primarily duetosales of proved properties and non-cash property exchangesofunprovedleasehold in Texasand NewMexico and thedisposition of theMarcellus Shale assets, andreceivedproceeds of approximately $192 million.

During 2019, EOG paid cash for propertyacquisitionsof$328 million in the United States. Additionally during 2019, EOG recognized net gains on assetdispositions of $124 million primarily due to sales of producing properties,acreage and otherassets, as wellasnon-cash propertyexchanges in New Mexico, and receivedproceeds of approximately$140 million.

During 2018, EOG recognized netgainsonassetdispositions of $175 million primarily duetonon-cash property exchangesinTexas,New Mexicoand Wyoming. Additionally, EOG received proceedsin2018 of approximately $227 million, primarily duetothe sale of itsUnited Kingdom operationsinthe fourth quarterof2018.

18.Leases

Lease costsare classified by the function of the ROU asset. The lease costs related to exploration and development activities are initially included in the Oil andGas Properties line on the ConsolidatedBalance Sheets and subsequently accounted forinaccordancewiththe Extractive Industries-Oil andGas Topicofthe ASC.Variable lease costrepresents costs incurredabove the contractualminimum payments and othercharges associated with leasedequipment,primarily for drilling and fracturing contracts classifiedasoperating leases. The components of leasecost for the yearsended December31, 2020 and 2019 were as follows (in millions):

2020 2019 OperatingLease Cost (1) $393 $497 Finance LeaseCost: Amortization of LeaseAssets 21 13 Interest on Lease Liabilities42 Variable LeaseCost 91 138 Short-Term LeaseCost 194 333 Total Lease Cost $703 $983

(1)Operating lease cost includes impairmentexpenses of $35 million in 2020.

F-40 Thefollowing table sets forththe amounts and classification of EOG's outstanding ROU assetsand related lease liabilitiesatDecember 31, 2020 and2019 and supplemental informationfor the yearsendedDecember31, 2020 and2019(in millions, except lease terms anddiscount rates):

Description Location on BalanceSheet 2020 2019 Assets Operating LeasesOtherAssets$869$ 773 FinanceLeases Property, Plant andEquipment, Net (1) 206 53 Total $1,075 $826

Liabilities Current Operating Leases Current Portion of Operating Lease Liabilities $295 $369 Finance LeasesCurrent Portion of Long-Term Debt 31 15 Long-Term Operating LeasesOtherLiabilities 641430 FinanceLeases Long-Term Debt 181 43 Total $1,148 $857

(1)Finance lease assetsare recorded netofaccumulated amortization of $81 million and $60 million at December 31,2020and 2019, respectively.

2020 2019 Weighted Average Remaining LeaseTerm (in years): OperatingLeases5.3 3.2 Finance Leases 7.6 4.7

Weighted Average Discount Rate: OperatingLeases3.4 %3.5 % Finance Leases 2.8 %3.0 %

Cash paid for leasesfor the years ended December 31, 2020 and2019was as follows (in millions):

2020 2019 Repayment of Operating LeaseLiabilities Associated with Operating Activities $223 $225 Repayment of Operating LeaseLiabilities Associated with InvestingActivities130 270 Repayment of FinanceLease Liabilities 19 13

Non-cash leasingactivities forthe yearendedDecember31, 2020, included the additions of $893 millionofoperating leases and $174 million of finance leases. Non-cash leasing activities forthe year endedDecember31, 2019, includedthe additionof$784 million of operating leases. Upon adoption of ASU 2016-02 effective January 1, 2019,EOG recognized operating lease ROUof$566 million.

F-41 At December 31, 2020, thefuture minimum lease payments undernon-cancellable leaseswereasfollows(in millions):

Operating Leases Finance Leases 2021 $323 $36 2022 210 32 2023 134 28 2024 96 29 2025 70 27 2026 and Beyond 206 87 TotalLease Payments1,039 239 Less: Discount to PresentValue 103 27 TotalLease Liabilities936 212 Less: Current Portion of LeaseLiabilities 295 31 Long-TermLease Liabilities $641 $181

At December 31, 2020, EOG had additional leases of $100 million, which areexpectedtocommencein2021 with leaseterms of two to nine years.

Prior to theadoption of ASU 2016-02 and otherrelated ASUs, the future minimumcommitments undernon- cancellable leases, including non-lease components and excluding contracts withlease terms of lessthan 12 months as December 31, 2018, were as follows (in millions):

Operating LeasesFinance Leases 2019 $380 $15 2020 21315 2021 86 15 2022 39 12 2023 30 8 2024 and Beyond 62 14 TotalLease Payments $810 $79

F-42 EOGRESOURCES, INC. SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIALSTATEMENTS (InThousands, Except Per ShareData, UnlessOtherwise Indicated) (Unaudited) Oil andGas ProducingActivities

The following disclosuresare made in accordancewith Financial Accounting Standards Board Accounting Standards UpdateNo. 2010-03 "Oiland Gas Reserve Estimationand Disclosures" and the United States Securitiesand Exchange Commission's(SEC) final rule on "ModernizationofOil and GasReporting."

Oil and Gas Reserves. Users of thisinformation should be awarethatthe process of estimating quantitiesof"proved," "proved developed" and "proved undeveloped" crude oil,naturalgas liquids (NGLs) and natural gasreservesiscomplex, requiring significantsubjective decisions in the evaluation of available geological, engineering andeconomicdata foreach reservoir. The data foragivenreservoir mayalso change substantially over time as aresultofnumerous factors, including, but not limitedto, additional development activity; evolving production history; crudeoil and condensate,NGL and natural gas prices; andcontinual reassessment of the viability of production under varying economic conditions.Consequently, material revisions (upward or downward) to existing reserve estimates mayoccur from time to time. Althoughreasonableeffort is made to ensure thatreserve estimatesreported represent the most accurateassessmentspossible, the significance of thesubjective decisionsrequired and variances in available data forvarious reservoirs make these estimatesgenerally lessprecise than other estimates presentedinconnection with financial statement disclosures. Forrelateddiscussion, seeITEM1A, Risk Factors.

Proved reserves represent estimatedquantities of crude oil, NGLsand natural gas, which, by analysisofgeoscience and engineering data,can be estimated, with reasonablecertainty, to be economically produciblefrom agiven date forward from knownreservoirs under then-existing economicconditions,operating methods and government regulationsbefore thetime at whichcontractsproviding the right to operateexpire,unless evidenceindicates thatrenewalisreasonablycertain, regardless of whether deterministic or probabilistic methods areusedfor the estimation.

Proved developed reservesare proved reserves expected to be recoveredunder operating methods being utilizedatthe time the estimateswere made, through wells andequipment in placeorifthe cost of any required equipment is relatively minor compared to thecost of anew well.

Proved undeveloped reserves (PUDs) arereserves thatare expected to be recoveredfromnew wells on undrilled acreage,orfromexisting wellswhere arelatively major expenditure is required for completion or recompletion. Reserves on undrilledacreage are limited to thosedirectly offsetting development spacing areas thatare reasonably certain of production when drilled, unless evidenceusing reliable technology exists thatestablishes reasonable certaintyofeconomic producibilityat greater distances.PUDs canberecorded in respectofaparticular undrilled location only if the location is scheduled,under the then-current drilling anddevelopment plan, to be drilledwithin five yearsfromthe datethatthe PUDs were recorded, unless specificfactors (such as those describedininterpretative guidance issued by the Staffofthe SEC) justifyalonger timeframe. Likewise,absent anysuchspecific factors, PUDs associatedwithaparticular undeveloped drilling location shall be removed from the estimates of proved reservesifthe location is scheduled,under the then-current drillingand development plan, to be drilled on adatethatisbeyondfiveyears fromthe date thatthe PUDs were recorded. EOG hasformulated developmentplans for alldrilling locations associated with its PUDsatDecember 31, 2020. Under these plans,eachPUD location willbedrilled within five yearsfrom the dateitwas recorded. Estimates for PUDs arenot attributed to any acreage for which an application of fluid injectionorother improved recovery techniqueiscontemplated, unless such techniques have been proved effective by actualprojectsinthe samereservoir or an analogous reservoir, or by other evidenceusingreliabletechnologyestablishing reasonablecertainty.

In making estimates of PUDs, EOG's technicalstaff, includingengineers and geoscientists, performdetailed technical analysisofeachpotentialdrilling location within its inventoryofprospects. In making adetermination as to which of these locations would penetrateundrilled portions of the formationthatcan be judged,withreasonable certainty, to be continuous and contain economicallyproducible crude oil,NGLsand naturalgas, studiesare conductedusing numerous data elementsand analysistechniques.EOG's technical staffestimates the hydrocarbons in place,bymapping the entiretyofthe play in question using seismic techniques, typicallyemploying two-dimensional and three-dimensional data. This analysisisintegrated with otherstatic data, including, but not limitedto, core analysis, mechanical properties of the formation,thermal maturity indicators, and welllogs of existing penetrations. Highly specializedequipment is utilized to prepare rock samplesinassessing microstructures which contributetoporosityand permeability.

Analysis of dynamicdataisthenincorporated to arrive at theestimated fractional recovery of hydrocarbons in place. Dataanalysistechniques employedinclude, but are not limited to, welltesting analysis,static bottom hole pressure analysis, flowing bottom hole pressure analysis, analysisofhistorical production trends, pressure transient analysis and ratetransient analysis. Applicationofproprietary ratetransient analysis techniques in low permeabilityrocks allowfor quantification of estimates of contribution to production from both fractures androckmatrix. F-43 EOGRESOURCES, INC.

SUPPLEMENTAL INFORMATIONTOCONSOLIDATEDFINANCIAL STATEMENTS (Continued)

Theimpact of optimal completion techniques is akey factorindeterminingifthe PUDs reflectedinprospective locationsare reasonablycertain of being economically producible. EOG's technical staff estimates therecovery improvement thatmightbeachievedwhen completing horizontal wells with multi-stagefracturestimulation. In theearly stages of development of aplay, EOGdetermines the optimallength of the horizontallateral and multi-stage fracture stimulation using the aforementioned analysis techniquesalong with pilot drilling programs andgathering of microseismicdata.

The process of analyzing static and dynamic data, wellcompletion optimizationdataand the resultsofearly development activities provides the appropriate level of certainty as wellassupport for the economic producibilityofthe plays in whichPUDs are reflected.EOG has found thisapproach to be effective based on successfulapplication in analogous reservoirs in lowpermeability resource plays.

Certain of EOG's Trinidad reservesare held underproduction sharing contracts where EOG'sinterest varieswith prices and production volumes. Trinidad reserves, as presented on anet basis,assumepricesinexistenceatthe time the estimatesweremade and EOG's estimate of future production volumes. Future fluctuations in prices,production rates or changes in politicalorregulatory environmentscould cause EOG'sshare of future production from Trinidadianreservestobe materiallydifferent from thatpresented.

Estimates of proved reservesatDecember 31, 2020,2019and 2018 were based on studiesperformed by the engineering staff of EOG. TheEngineering and Acquisitions Department is directlyresponsible for EOG'sreserve evaluation process and consistsof17professionals, allofwhomhold, at aminimum, bachelor'sdegreesinengineering, and four of whom are Registered Professional Engineers. TheVicePresident, Engineering and Acquisitionsisthe manager of thisdepartment and is the primarytechnical person responsible for thisprocess. The Vice President, Engineering and Acquisitions holds aBachelor of SciencedegreeinPetroleum Engineering, has34years of experienceinreserve evaluations and is aRegisteredProfessional Engineer.

EOG'sreserves estimation process is acollaborative effort coordinated by the Engineering and Acquisitions Departmentincompliance with EOG's internalcontrols for suchprocess. Reserveinformationaswell as models usedto estimatesuchreserves are storedonsecured databases. Non-technical inputsusedinreserve estimation models, including crudeoil, NGLand natural gasprices, production costs, transportation costs, future capitalexpendituresand EOG'snet ownershippercentages, are obtainedfromotherdepartments within EOG. EOG'sInternalAudit Departmentconductstesting withrespect to suchnon-technicalinputs. Additionally, EOG engagesDeGolyerand MacNaughton (D&M), independent petroleum consultants, to perform independent reservesevaluation of selectEOG properties comprising not less than75% of EOG's estimatesofproved reserves. EOG's Board of Directors requires thatD&M's and EOG's reserve quantities forthe properties evaluatedbyD&M vary by no more than 5% in the aggregate. Once completed, EOG'syear-end reserves are presentedtosenior management, including the Chairman of the Board and Chief Executive Officer; the Chief Operating Officer;the President; the Executive Vice President,Explorationand Production; and the ExecutiveVicePresident andChief Financial Officer, for approval.

Opinions by D&Mfor the yearsended December31, 2020, 2019 and 2018 coveredproducing areas containing 83%, 82% and 79%, respectively, of proved reserves of EOG on anet-equivalent-barrel-of-oil basis. D&M'sopinions indicatethat theestimates of proved reservesprepared by EOG'sEngineering and AcquisitionsDepartment forthe properties reviewed by D&M,when compared in totalonanet-equivalent-barrel-of-oil basis,donot differ materially from the estimates prepared by D&M.Specifically, suchestimates by D&M in the aggregatevariedbynot more than5%fromthose prepared by the Engineering and Acquisitions Department of EOG. AllreportsbyD&M were developed utilizing geologicaland engineering dataprovidedbyEOG.The report of D&MdatedJanuary 26, 2021, which contains furtherdiscussion of the reserveestimates and evaluations prepared by D&M, as well as the qualifications of D&M's technicalpersonprimarily responsible foroverseeing such estimates andevaluations, is attached as Exhibit 99.1 to thisAnnualReportonForm10-K and incorporated herein by reference.

No major discovery or otherfavorable or adverse event subsequent to December 31, 2020, is believed to havecaused a material change in theestimates of netproved reservesasofthatdate.

The following tables setforth EOG's netprovedreservesatDecember 31 foreachofthe four years in the period ended December 31, 2020, and the changes in the netprovedreservesfor each of the threeyears in the period ended December 31, 2020, as estimated by the Engineering andAcquisitions Department of EOG:

F-44 EOGRESOURCES, INC.

SUPPLEMENTAL INFORMATIONTOCONSOLIDATEDFINANCIAL STATEMENTS(Continued)

NETPROVED RESERVE SUMMARY

United Other States Trinidad International (1) Total NETPROVEDRESERVES

Crude Oil(MBbl) (2) Netprovedreserves at December31, 2017 1,304,071 898 8,004 1,312,973 Revisions of previous estimates (13,237) (183)44(13,376) Purchases in place 2,743 ——2,743 Extensions, discoveries andother additions 383,003 —15383,018 Salesinplace (768)— (6,310) (7,078) Production (144,128) (298) (1,542) (145,968) Netprovedreserves at December31, 2018 1,531,684 417 211 1,532,312 Revisions of previous estimates (42,959) 85 (8)(42,882) Purchases in place2,859 ——2,859 Extensions, discoveries andotheradditions 369,968 —28369,996 Salesinplace (1,282) ——(1,282) Production (166,310) (236) (40) (166,586) Netprovedreserves at December31, 2019 1,693,960 266 191 1,694,417 Revisions of previous estimates (225,375) (19) (18) (225,412) Purchases in place2,176 ——2,176 Extensions, discoveries andotheradditions 194,724 863 —195,587 Salesinplace (3,183)— —(3,183) Production (149,402) (355) (30) (149,787) Netproved reservesatDecember31, 2020 1,512,900 755 143 1,513,798

Natural GasLiquids (MBbl) (2) Netprovedreserves at December31, 2017 503,473 ——503,473 Revisionsofprevious estimates 23,942 ——23,942 Purchases in place2,006 ——2,006 Extensions, discoveriesand other additions 127,409 ——127,409 Salesinplace (41) ——(41) Production (42,460) ——(42,460) Netprovedreserves at December31, 2018 614,329 ——614,329 Revisions of previous estimates 5,380 ——5,380 Purchases in place1,948 ——1,948 Extensions, discoveriesand otheradditions 167,782 ——167,782 Sales in place(855) ——(855) Production (48,892) ——(48,892) Netprovedreserves at December31, 2019 739,692 ——739,692 Revisions of previous estimates (59,790) ——(59,790) Purchases in place3,831 ——3,831 Extensions, discoveriesand otheradditions 180,205 ——180,205 Sales in place(1,399) ——(1,399) Production (49,796) ——(49,796) Net proved reserves at December31, 2020 812,743 ——812,743

F-45 EOGRESOURCES, INC.

SUPPLEMENTAL INFORMATIONTOCONSOLIDATEDFINANCIAL STATEMENTS(Continued)

United Other States Trinidad International (1) Total Natural Gas(Bcf) (3) Netprovedreserves at December31, 2017 3,898.5 313.4 51.2 4,263.1 Revisions of previous estimates (127.2)20.715.0 (91.5) Purchases in place 41.3 ——41.3 Extensions, discoveries andother additions 951.4 —4.6 956.0 Sales in place (22.2) ——(22.2) Production (351.2) (97.1) (11.2) (459.5) Netprovedreserves at December31, 2018 4,390.6 237.0 59.6 4,687.2 Revisions of previous estimates (184.4)47.02.6 (134.8) Purchases in place71.7 ——71.7 Extensions, discoveries andotheradditions 1,175.9 87.5 9.7 1,273.1 Salesinplace (14.5) ——(14.5) Production (404.5) (95.4) (13.1) (513.0) Netprovedreserves at December31, 2019 5,034.8 276.1 58.8 5,369.7 Revisions of previous estimates (497.7) 4.8 1.6 (491.3) Purchases in place26.3 ——26.3 Extensions, discoveries andotheradditions 1,077.9 53.9 —1,131.8 Salesinplace (157.3) ——(157.3) Production (441.4) (65.9) (11.6) (518.9) Netproved reservesatDecember31, 2020 5,042.6 268.9 48.8 5,360.3

OilEquivalents(MBoe) (2) Netprovedreserves at December31, 2017 2,457,302 53,142 16,526 2,526,970 Revisions of previous estimates (10,500) 3,272 2,544 (4,684) Purchases in place11,640 ——11,640 Extensions, discoveries andotheradditions 668,972 —778 669,750 Salesinplace (4,509)— (6,310)(10,819) Production (245,127) (16,478) (3,406) (265,011) Netprovedreserves at December31, 2018 2,877,778 39,936 10,132 2,927,846 Revisions of previous estimates (68,317) 7,915 431 (59,971) Purchases in place16,761 ——16,761 Extensions, discoveries andother additions 733,730 14,577 1,661 749,968 Salesinplace (4,555) ——(4,555) Production (282,619) (16,130) (2,232) (300,981) Netprovedreserves at December31, 2019 3,272,778 46,298 9,992 3,329,068 Revisions of previous estimates (368,127) 773 259 (367,095) Purchases in place10,398 ——10,398 Extensions, discoveries andother additions554,5859,840 —564,425 Salesinplace (30,802) ——(30,802) Production (272,757) (11,347) (1,969) (286,073) Netproved reservesatDecember31, 2020 3,166,075 45,564 8,282 3,219,921

(1) OtherInternational includes EOG's UnitedKingdom, China and Canada operations. TheUnitedKingdom operations were soldinthe fourth quarterof2018. (2) Thousand barrels or thousand barrelsofoil equivalent, as applicable; oil equivalents include crude oil and condensate, NGLs and natural gas. Oilequivalentsare determinedusing aratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 thousand cubicfeet of natural gas. (3) Billion cubic feet.

F-46 EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATIONTOCONSOLIDATEDFINANCIAL STATEMENTS(Continued)

During 2020, EOG added564 million barrels of oil equivalent (MMBoe)ofproved reservesfromdrilling activities and technicalevaluation of major proved areas, primarilyinthe Permian Basin.Approximately 67%ofthe 2020 reserve additions were crude oiland condensateand NGLs, and substantially allwereinthe United States. Sales in placeof31 MMBoe were primarily relatedtothe saleofthe Marcellus Shale assets andthe saleorexchange of other producing assets. Revisions of previous estimates of negative 367 MMBoe for 2020 included adownward revision of 278 MMBoe primarily due to decreases in the average crude oil,NGLsand naturalgas pricesusedinthe December 31, 2020,reserves estimation as compared to the prices usedinthe prior yearestimate. The primaryareas affectedwerethe EagleFord andthe Rocky Mountain area. Purchases in place of 10 MMBoe were primarily related to thePermian Basin and thepurchase or exchange of otherproducing assets.

During 2019, EOG added750 MMBoe of proved reserves from drilling activities and technical evaluationofmajor proved areas,primarilyinthe Permian Basin,the EagleFordand the Rocky Mountain area. Approximately72% of the 2019 reserve additions were crude oil andcondensate andNGLs, and substantially all were in theUnitedStates. Sales in place of 5 MMBoe were primarily related to the sale of certain South Texasareaoperations and the saleorexchange of other producing assets. Revisionsofprevious estimatesofnegative 60 MMBoe for 2019 included adecrease in the average crude oil,NGLs andnatural gas pricesusedinthe December 31, 2019, reservesestimationascompared to the pricesusedinthe prior year estimate. The primaryareaaffected was the Rocky Mountain area. Purchasesinplace of 17 MMBoe were primarily relatedto the South Texasarea.

During 2018, EOG added670 MMBoe of provedreserves from drilling activities and technical evaluationofmajor proved areas, primarily in the Permian Basin,the EagleFord,the Rocky Mountain areaand the Mid-Continentarea. Approximately 76% of the 2018 reserve additions were crudeoil andcondensate andNGLs, and substantiallyall were in the United States. Sales in place of 11 MMBoe were primarily relatedtothe sale of the United Kingdom operations andthe saleor exchange of otherproducing assets. Revisions of previousestimates of negative5MMBoe for 2018 included an upward revision of 35 MMBoe primarilydue to increases in the average crude oil,NGLs andnaturalgas pricesusedinthe December 31,2018, reservesestimationascompared to the prices used in the prior year estimate. The primaryareas affected were in the Rocky Mountain area, the Eagle Ford and the Permian Basin. Downwardrevisions other thanprice of 40 MMBoe resulted primarily from changes in production forecastsand higher production costs. Purchasesinplace of 12 MMBoe were primarily related to theSouth Texasarea.

F-47 EOGRESOURCES, INC.

SUPPLEMENTAL INFORMATIONTOCONSOLIDATEDFINANCIAL STATEMENTS(Continued)

United Other StatesTrinidad International (1) Total NETPROVEDDEVELOPED RESERVES Crude Oil(MBbl) December31, 2017 605,405 898 7,933 614,236 December31, 2018 712,218 417 150 712,785 December31, 2019 801,189 266 143 801,598 December31, 2020 791,744 755 93 792,592 Natural GasLiquids (MBbl) December31, 2017 286,872 ——286,872 December31, 2018 341,386 ——341,386 December31, 2019 387,253 ——387,253 December31, 2020 391,708 ——391,708 Natural Gas(Bcf) December31, 2017 2,450.8299.2 29.3 2,779.3 December31, 2018 2,699.0223.9 40.9 2,963.8 December31, 2019 2,974.6177.7 41.8 3,194.1 December31, 2020 2,586.1171.1 31.6 2,788.8 OilEquivalents (MBoe) December31, 2017 1,300,758 50,779 12,798 1,364,335 December31, 2018 1,503,44137,7466,950 1,548,137 December31, 2019 1,684,20929,8867,117 1,721,212 December31, 2020 1,614,46229,2685,368 1,649,098 NETPROVEDUNDEVELOPEDRESERVES Crude Oil(MBbl) December31, 2017 698,666 —71698,737 December31, 2018 819,466 —61819,527 December31, 2019 892,771 —48892,819 December31, 2020 721,156 —50721,206 Natural GasLiquids (MBbl) December31, 2017 216,601 ——216,601 December31, 2018 272,943 ——272,943 December31, 2019 352,439 ——352,439 December31, 2020 421,035 ——421,035 Natural Gas(Bcf) December31, 2017 1,447.7 14.2 21.9 1,483.8 December31, 2018 1,691.613.118.71,723.4 December31, 2019 2,060.298.417.02,175.6 December31, 2020 2,456.597.817.22,571.5 OilEquivalents (MBoe) December31, 2017 1,156,544 2,363 3,728 1,162,635 December31, 2018 1,374,3372,190 3,182 1,379,709 December31, 2019 1,588,56916,4122,875 1,607,856 December31, 2020 1,551,61316,2962,914 1,570,823

(1) OtherInternational includes EOG's UnitedKingdom, China and Canada operations. The UnitedKingdom operationsweresoldinthe fourth quarterof2018.

F-48 EOGRESOURCES, INC.

SUPPLEMENTALINFORMATIONTOCONSOLIDATEDFINANCIAL STATEMENTS(Continued)

Net Proved Undeveloped Reserves. Thefollowing table presentsthe changes in EOG's total PUDs during 2020,2019 and 2018 (inMBoe):

2020 2019 2018

BalanceatJanuary 11,607,856 1,379,709 1,162,635 Extensions and Discoveries456,073 578,317 490,725 Revisions (277,325) (49,837) (8,244) Acquisition of Reserves471,711 311 SaleofReserves (3,670) —— Conversion to Proved DevelopedReserves(212,158) (302,044) (265,718) Balance at December31 1,570,823 1,607,856 1,379,709

For the twelve-month period endedDecember 31,2020, total PUDs decreasedby37MMBoeto1,571 MMBoe.EOG addedapproximately 7MMBoeofPUDs through drilling activities where the wells were drilled butsignificant expenditures remained for completion. Based on thetechnology employedbyEOG to identifyand record PUDs (seediscussion of technology employedonpages F-43 and F-44 of thisAnnual ReportonForm10-K), EOG added 449 MMBoe of PUDs. The PUD additions were primarily in thePermian Basin and 67%ofthe additions were crudeoil andcondensate andNGLs. During 2020,EOG drilled and transferred 212MMBoeofPUDs to proved developed reserves at atotalcapital cost of $1,674 million. Revisions of previous estimates of negative 277 MMBoe of PUDs for 2020 includedadownwardprice revisionof77MMBoe duetodecreases in the average crude oil, NGLsand naturalgas prices usedinthe December 31, 2020, reserves estimationas compared to theprices used in the prior yearestimate. Revisions other than price of negative 200 MMBoe were primarily related to theremoval of PUD locations duetolower projected capitalspending over the next five years as comparedtothe prior year projections. Theprimaryareasaffected were the EagleFordand the Rocky Mountainarea.All PUDs,including drilledbut uncompleted wells (DUCs), are scheduledfor completionwithin five years of the original reserve booking.

For the twelve-month period ended December31, 2019, total PUDs increased by 228 MMBoe to 1,608 MMBoe. EOG addedapproximately38MMBoeofPUDs through drillingactivitieswhere the wells were drilledbut significant expenditures remainedfor completion.Based on the technologyemployedbyEOG to identify and record PUDs, EOG added 540 MMBoe.The PUD additions were primarily in the Permian Basin, the EagleFord and, to alesser extent,the Rocky Mountain area, and 73% of the additions were crude oiland condensate and NGLs.During 2019, EOG drilled and transferred 302 MMBoe of PUDs to proved developedreservesatatotal capitalcostof$3,032 million.

For the twelve-month period ended December31, 2018, total PUDs increased by 217 MMBoe to 1,380 MMBoe. EOG addedapproximately 31 MMBoe of PUDs through drillingactivities where the wells were drilledbut significant expenditures remainedfor completion.Based on the technologyemployedbyEOG to identify and record PUDs, EOG added 460 MMBoe.The PUD additions were primarily in the Permian Basin,Anadarko Basin, the Eagle Ford and,toalesser extent, the RockyMountain area, and 80% of the additions were crude oiland condensate andNGLs. During 2018,EOG drilled and transferred266 MMBoe of PUDs to proved developedreserves at atotal capitalcostof$2,745 million.

F-49 EOGRESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)

Capitalized Costs Relating to Oiland Gas Producing Activities. The followingtable setsforththe capitalized costs relating to EOG's crude oil, NGLs and natural gas producing activities at December31, 2020 and 2019: 2020 2019

Provedproperties$61,724,487 $59,229,686 Unprovedproperties3,068,311 3,600,729 Total 64,792,798 62,830,415 Accumulateddepreciation, depletion andamortization (38,750,852) (35,033,085) Netcapitalizedcosts $26,041,946 $27,797,330

CostsIncurred in Oiland Gas Property Acquisition, Exploration and Development Activities. The acquisition, exploration and development costs disclosed in the following tables are in accordance with definitions in the Extractive Industries -Oil andGas Topicofthe Accounting Standards Codification (ASC).

Acquisition costs include costs incurred to purchase,lease or otherwise acquire property.

Exploration costs include additions to exploratory wells, includingthose in progress, and explorationexpenses.

Development costs includeadditions to production facilities and equipmentand additionstodevelopment wells, including thoseinprogress.

F-50 EOGRESOURCES, INC.

SUPPLEMENTAL INFORMATIONTOCONSOLIDATEDFINANCIAL STATEMENTS(Continued)

Thefollowing table setsforth costs incurred related to EOG's oiland gas activities forthe yearsended December 31, 2020,2019and 2018:

United Other StatesTrinidad International (1) Total 2020 Acquisition Costs of Properties Unproved (2) $264,778 $—$—$264,778 Proved (3) 97,073 —38,089 135,162 Subtotal 361,851 —38,089 399,940 Exploration Costs203,403 81,216 11,409 296,028 Development Costs (4) 2,998,155 4,036 20,072 3,022,263 Total $3,563,409 $85,252 $69,570 $3,718,231 2019 Acquisition Costs of Properties Unproved (5) $276,092 $—$—$276,092 Proved (6) 379,938 ——379,938 Subtotal656,030 ——656,030 Exploration Costs213,505 46,616 13,218 273,339 Development Costs (7) 5,661,753 25,007 12,096 5,698,856 Total $6,531,288 $71,623 $25,314 $6,628,225 2018 Acquisition Costs of Properties Unproved (8) $486,081 $1,258 $—$487,339 Proved (9) 123,684 ——123,684 Subtotal609,765 1,258 —611,023 Exploration Costs157,222 22,511 13,895 193,628 Development Costs (10) 5,605,264 (12,863) 22,628 5,615,029 Total $6,372,251 $10,906 $36,523 $6,419,680

(1) OtherInternational primarily consistsofEOG's United Kingdom, China and Canadaoperations. EOGbegan an exploration program in Oman in the third quarter of 2020. The UnitedKingdom operationsweresold in thefourthquarter of 2018. (2) Includes non-cash unprovedleasehold acquisition costs of $197million related to property exchanges. (3) Includes non-cash proved property acquisitioncosts of $15 million related to propertyexchanges. (4) Includes Asset RetirementCosts of $97 million and $20 millionfor theUnitedStatesand Other International,respectively. Excludes other property, plantand equipment. (5) Includes non-cash unproved leasehold acquisition costs of $98 million related to property exchanges. (6) Includes non-cash proved property acquisitioncosts of $52 million related to propertyexchanges. (7) Includes Asset Retirement Costs of $181 million, $1 million and $4 millionfor theUnited States, Trinidadand Other International, respectively. Excludes other property, plantand equipment. (8) Includes non-cash unproved leasehold acquisition costs of $291million related to property exchanges. (9) Includes non-cash proved property acquisitioncosts of $71 million related to propertyexchanges. (10) Includes Asset Retirement Costsof$90 million,$(12) million and $(8) million for the United States, Trinidad and Other International, respectively. Excludes other property, plantand equipment.

F-51 EOGRESOURCES, INC.

SUPPLEMENTAL INFORMATIONTOCONSOLIDATEDFINANCIAL STATEMENTS(Continued)

Results of Operationsfor Oiland Gas Producing Activities (1).The following table sets forthresults of operations for oiland gasproducing activities forthe years endedDecember31, 2020, 2019 and 2018:

United Other States Trinidad International (2) Total 2020 Crude Oil andCondensate, NaturalGas Liquids and Natural Gas Revenues $7,055,098 $179,690 $55,468 $7,290,256 Other60,989 (35) —60,954 Total 7,116,087 179,65555,468 7,351,210 ExplorationCosts 136,2661,909 7,613 145,788 Dry Hole Costs 13,055 —2813,083 Transportation Costs 734,071747 171734,989 Gathering and Processing Costs 459,211— —459,211 Production Costs1,479,976 26,964 10,407 1,517,347 Impairments 2,018,283 815 80,682 2,099,780 Depreciation, Depletion andAmortization 3,192,000 60,328 15,747 3,268,075 Income(Loss) Before Income Taxes (916,775)88,892(59,180)(887,063) IncomeTax Provision (220,437)23,5263,428 (193,483) Results of Operations $(696,338) $65,366 $(62,608)$ (693,580) 2019 Crude Oil andCondensate, NaturalGas Liquids and Natural Gas Revenues $11,250,853 $269,957 $60,635 $11,581,445 Other134,325 18 15 134,358 Total 11,385,178 269,97560,65011,715,803 ExplorationCosts 130,3024,290 5,289 139,881 Dry Hole Costs 11,133 13,033 3,835 28,001 Transportation Costs 753,5584,014 728 758,300 Gathering and Processing Costs 479,102— —479,102 Production Costs2,063,078 30,539 40,369 2,133,986 Impairments510,948 5,713 1,235 517,896 Depreciation, Depletion andAmortization 3,560,609 79,156 17,832 3,657,597 Income(Loss) Before Income Taxes 3,876,448 133,230(8,638) 4,001,040 IncomeTax Provision 884,450 54,980 3,152 942,582 Results of Operations $2,991,998$ 78,250 $(11,790)$ 3,058,458 2018 Crude Oil andCondensate, NaturalGas Liquids and Natural Gas Revenues $11,488,620 $302,112 $155,755 $11,946,487 Other89,708 (49) (24) 89,635 Total 11,578,328 302,063155,731 12,036,122 ExplorationCosts 121,57221,4026,025 148,999 Dry HoleCosts 4,983 —422 5,405 Transportation Costs 742,7923,236 848 746,876 Gathering and Processing Costs (3) 404,471—32,502436,973 Production Costs1,924,504 33,506 70,073 2,028,083 Impairments344,595 —2,426 347,021 Depreciation, Depletion andAmortization 3,181,801 91,788 46,687 3,320,276 Income(Loss) Before Income Taxes 4,853,610 152,131(3,252) 5,002,489 IncomeTax Provision 1,086,077 12,170 1,898 1,100,145 Results of Operations $3,767,533$ 139,961 $(5,150) $3,902,344

(1) Excludes gainsorlosses on the mark-to-market of financialcommodityderivativecontracts, gainsorlosses on sales of reserves and related assets, interest charges and general corporate expenses for each of thethreeyears in theperiod ended December 31,2020. (2) OtherInternational primarily consists of EOG's United Kingdom,Chinaand Canadaoperations.EOG begananexploration program in Oman in the thirdquarterof2020. The United Kingdomoperations were soldinthe fourthquarterof2018. (3) Effective January 1, 2018, EOG adopted the provisions of Accounting Standards Update (ASU) 2014-09, "Revenue From Contracts With Customers" (ASU 2014-09). In connection with the adoption of ASU 2014-09, EOG presents natural gas processing feesrelating to certain processingand marketingagreements withinits UnitedStates segment as Gathering andProcessing Costs instead of as a deduction to Natural Gas Revenues. There was no impact to operating incomeornet income resulting from changes to the presentation of naturalgas processing fees (seeNote1toConsolidated Financial Statements). F-52 EOGRESOURCES, INC.

SUPPLEMENTAL INFORMATIONTOCONSOLIDATEDFINANCIAL STATEMENTS(Continued)

Thefollowing table setsforthproduction costs per barrel of oil equivalent,excluding severance/production andad valorem taxes, for theyears ended December 31, 2020, 2019 and2018:

United Other States Trinidad International (1) Composite

Year EndedDecember31, 2020 $3.75 $2.33 $6.78 $3.72 Year Ended December 31, 2019 $4.59$ 1.85 $18.26 $4.54 Year Ended December 31, 2018 $4.84$ 1.67 $20.19 $4.84

(1) OtherInternational primarily consists of EOG's UnitedKingdom, China and Canadaoperations.The United Kingdom operations were sold in the fourthquarter of 2018.

StandardizedMeasure of Discounted Future NetCashFlows Relating to Proved Oiland Gas Reserves. Thefollowing informationhas been developed utilizing proceduresprescribedbythe Extractive Industries -Oil andGas Topic of the ASC and based on crude oil, NGL andnaturalgas reserves and productionvolumes estimated by the Engineering and Acquisitions Department of EOG. The estimateswerebased on a12-monthaverage forcommodity pricesfor the years 2020, 2019 and 2018. The following information maybeuseful for certaincomparative purposes, but should not be solely relied upon in evaluating EOGorits performance. Further, information contained in thefollowingtable should not be consideredas representative of realisticassessments of future cash flows, nor should the Standardized Measure of DiscountedFuture Net Cash Flows be viewed as representative of thecurrent value of EOG.

The future cash flows presented below arebased on sales prices, cost rates and statutoryincometax rates in existence as of the dateofthe projections. It is expected that material revisions to some estimatesofcrude oil,NGL and natural gas reservesmay occur in the future,development andproduction of the reserves mayoccur in periods other thanthose assumed, and actualpricesrealized andcostsincurred mayvarysignificantly from thoseused.

Management does not relyupon the following information in making investment andoperating decisions. Such decisions arebased upon awide range of factors, includingestimates of probableand possiblereserves as wellasproved reserves, and varying price andcost assumptions consideredmore representative of arangeofpossibleeconomic conditions that may be anticipated.

F-53 EOGRESOURCES, INC.

SUPPLEMENTAL INFORMATIONTOCONSOLIDATEDFINANCIAL STATEMENTS(Continued)

Thefollowing table sets forth thestandardizedmeasure of discountedfuturenet cashflows from projected production of EOG's oiland gasreservesfor the years endedDecember31, 2020, 2019 and2018:

United Other States Trinidad International (1) Total 2020 Future cash inflows (2) $73,726,893 $900,815 $281,658 $74,909,366 Future production costs (34,618,860) (153,275) (53,933) (34,826,068) Future developmentcosts (15,159,373) (226,430)(18,400)(15,404,203) Future income taxes (4,336,578) (81,368) (24,311) (4,442,257) Future netcashflows 19,612,082 439,742 185,014 20,236,838 Discount to presentvalue at 10% annual rate (8,410,282) (100,350)(36,194)(8,546,826) Standardized measure of discounted future netcash flows relating to proved oiland gasreserves $11,201,800 $339,392 $148,820 $11,690,012 2019 Future cash inflows (3) $120,359,769 $813,102 $305,491 $121,478,362 Future production costs (42,387,801) (166,705)(87,381)(42,641,887) Future developmentcosts (20,355,746) (212,303)(18,400)(20,586,449) Future incometaxes (11,459,567) (73,508) (32,423) (11,565,498) Future netcashflows 46,156,655 360,586 167,287 46,684,528 Discount to presentvalue at 10% annual rate (21,042,593) (86,009) (35,161) (21,163,763) Standardized measure of discounted future netcash flows relating to proved oiland gasreserves $25,114,062 $274,577 $132,126 $25,520,765 2018 Future cash inflows (4) $133,066,375 $749,695 $303,620 $134,119,690 Future production costs (42,351,174) (204,444) (99,024) (42,654,642) Future developmentcosts (16,577,794) (78,199) (11,900) (16,667,893) Future incometaxes (14,756,011) (174,382) (31,748) (14,962,141) Future netcashflows 59,381,396 292,670 160,948 59,835,014 Discount to presentvalue at 10% annual rate (27,348,744) (26,832) (33,483) (27,409,059) Standardized measure of discounted future netcash flows relating to provedoil and gasreserves $32,032,652 $265,838 $127,465 $32,425,955

(1) OtherInternational includes EOG's UnitedKingdom, China and Canada operations.The UnitedKingdom operationsweresoldinthe fourth quarterof2018. (2) Estimated crude oil pricesusedtocalculate 2020 future cash inflows for the United States,Trinidad and Other International were $37.19, $26.75, and $41.87, respectively. Estimated NGL price used to calculate 2020 future cashinflows for the United Stateswas $12.47. Estimated natural gas prices used to calculate 2020 future cash inflows for the United States, Trinidad and Other International were $1.45, $3.28, and $5.65,respectively. (3) Estimated crude oil pricesused to calculate 2019futurecash inflows for the United States,Trinidad and Other International were $57.51, $46.77 and $57.22, respectively. Estimated NGL priceused to calculate 2019 future cash inflowsfor theUnitedStates was $16.91. Estimated natural gas prices used to calculate 2019 future cash inflows for the United States, Trinidad and Other International were $2.07, $2.90and $5.01, respectively. (4) Estimated crude oil pricesused to calculate 2018futurecash inflows for the United States,Trinidad and Other International were $68.54, $55.66 and $61.66, respectively. Estimated NGL priceused to calculate 2018 future cash inflowsfor theUnitedStates was $27.83. Estimated natural gas prices used to calculate 2018 future cash inflows for the United States, Trinidad and Other International were $2.50, $3.06and $4.88, respectively.

F-54 EOGRESOURCES, INC.

SUPPLEMENTAL INFORMATIONTOCONSOLIDATEDFINANCIAL STATEMENTS(Continued)

Changes in Standardized Measure of DiscountedFuture NetCashFlows. The following table sets forththe changes in the standardized measure of discountedfuture net cash flowsatDecember31, for each of the threeyearsinthe period ended December 31, 2020:

United Other States Trinidad International (1) Total

December 31, 2017 $17,756,935 $332,427 $238,298 $18,327,660 Sales and transfers of oil and gasproduced, netofproduction costs (8,416,853) (265,370) (52,399) (8,734,622) Netchanges in prices andproduction costs 12,750,466 84,353 21,610 12,856,429 Extensions,discoveries, additions andimproved recovery, net of related costs 8,418,666 —12,287 8,430,953 Development costs incurred2,732,560 —12,600 2,745,160 Revisions of estimateddevelopment cost (410,741)4,030 (3,814) (410,525) Revisions of previous quantityestimates (173,084) 39,608 31,750 (101,726) Accretion of discount 1,967,592 50,191 24,839 2,042,622 Netchangeinincome taxes (4,965,373) 3,844 (11,529) (4,973,058) Purchases of reservesinplace 116,887 ——116,887 Sales of reservesinplace(35,874) —(82,058) (117,932) Changes in timing and other 2,291,471 16,755 (64,119) 2,244,107 December 31, 2018 32,032,652 265,838 127,465 32,425,955 Salesand transfers of oil and gasproduced, net of production costs (7,955,115) (235,404) (19,919) (8,210,438) Netchanges in prices andproductioncosts (10,973,981) 65,962 27,572 (10,880,447) Extensions, discoveries, additions andimprovedrecovery, net of related costs 5,608,038 85,233 16,287 5,709,558 Development costs incurred 3,003,510 22,820 5,820 3,032,150 Revisions of estimated development cost (597,869) (129,047) (11,108) (738,024) Revisions of previous quantityestimates (812,781) 116,062 1,198 (695,521) Accretion of discount 3,891,701 43,148 14,909 3,949,758 Netchangeinincome taxes 1,454,050 93,975 682 1,548,707 Purchases of reservesinplace 98,539 ——98,539 Salesofreservesinplace(50,651) ——(50,651) Changesintiming andother(584,031) (54,010) (30,780) (668,821) December 31, 2019 25,114,062 274,577 132,126 25,520,765 Salesand transfers of oil and gasproduced, net of production costs (4,381,840) (151,979) (45,355) (4,579,174) Netchanges in prices andproductioncosts (18,624,768) 131,859 46,916 (18,445,993) Extensions, discoveries, additions andimproved recovery, net of related costs 1,436,988 64,385 —1,501,373 Development costs incurred 1,674,800— —1,674,800 Revisions of estimateddevelopment cost 4,148,768(11,161) —4,137,607 Revisionsofprevious quantityestimates (3,307,180) 11,632 (1,764) (3,297,312) Accretion of discount 3,054,437 34,624 15,307 3,104,368 Netchangeinincometaxes3,497,362 (12,185) 3,022 3,488,199 Purchasesofreserves in place49,232 ——49,232 Salesofreservesinplace (156,293) ——(156,293) Changesintiming andother (1,303,768) (2,360) (1,432) (1,307,560) December 31, 2020 $11,201,800 $339,392 $148,820 $11,690,012

(1) OtherInternational includes EOG's UnitedKingdom, China and Canada operations. TheUnitedKingdom operations were soldinthe fourth quarterof2018.

F-55 EOGRESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIALSTATEMENTS (Concluded)

Unaudited Quarterly Financial Information (In Thousands, Except Per ShareData) QuarterEndedMar 31 Jun 30 Sep 30 Dec 31 2020 Operating Revenues andOther $4,717,692 $1,103,374 $2,245,484 $2,965,498 Operating Income (Loss) $57,585 $(1,086,549) $(2,714) $487,662 Income (Loss) Before Income Taxes $31,003 $(1,145,262) $(52,555) $427,760 Income Tax Provision(Benefit) 21,190 (235,878) (10,088) 90,294 NetIncome(Loss) $9,813 $(909,384) $(42,467) $337,466 NetIncome(Loss) PerShare (1) Basic $0.02$ (1.57) $(0.07) $0.58 Diluted $0.02$ (1.57) $(0.07) $0.58 Average Number of CommonShares Basic 578,462 578,719 579,055 579,624 Diluted 580,283 578,719 579,055 580,885 2019 Operating Revenues andOther $4,058,642 $4,697,630 $4,303,455 $4,320,246 Operating Income $876,530 $1,130,771 $827,959 $863,751 Income Before Income Taxes $827,236 $1,089,366 $797,457 $831,208 Income Tax Provision 191,810 241,525 182,335 194,687 NetIncome$635,426 $847,841 $615,122 $636,521 NetIncomePer Share (1) Basic $1.10$ 1.47 $1.06$ 1.10 Diluted $1.10$ 1.46 $1.06$ 1.10 Average Number of CommonShares Basic 577,207 577,460 577,839 578,219 Diluted 580,222 580,247 581,271 580,849

(1) The sum of quarterly net income (loss) per share may not agree with totalyearnet income (loss) per share as each quarterlycomputation is based on the weighted average of commonsharesoutstanding.

F-56 EXHIBITS

Exhibits notincorporated herein by reference to aprior filing are designated by (i) an asterisk (*) andare filed herewith; or (ii) apound sign (#) and are not filed herewith,and,pursuanttoItem601(b)(4)(iii)(A) of Regulation S-K, the registrant hereby agrees to furnish acopy of suchexhibit to the UnitedStates Securitiesand Exchange Commission (SEC) upon request.

Exhibit Number Description 3.1(a) - Restated CertificateofIncorporation, dated September 3, 1987 (Exhibit 3.1(a) to EOG's Annual Report on Form 10-K for theyearended December 31,2008) (SECFileNo. 001-09743). 3.1(b) - Certificate of Amendment of Restated Certificate of Incorporation, datedMay 5, 1993 (Exhibit 4.1(b) to EOG's Registration StatementonForm S-8, SECFileNo. 33-52201,filed February 8, 1994). 3.1(c) - Certificate of Amendment of RestatedCertificate of Incorporation, datedJune14, 1994 (Exhibit 4.1(c)to EOG's Registration StatementonForm S-8, SECFileNo. 33-58103,filed March 15, 1995). 3.1(d) - Certificate of Amendment of Restated CertificateofIncorporation, dated June 11, 1996 (Exhibit 3(d) to EOG's Registration StatementonForm S-3, SECFileNo. 333-09919, filed August 9, 1996). 3.1(e) - Certificate of Amendment of Restated CertificateofIncorporation, dated May 7, 1997 (Exhibit 3(e) to EOG's Registration StatementonForm S-3, SECFileNo. 333-44785, filed January 23, 1998). 3.1(f) - Certificate of Ownership and MergerMergingEOG Resources,Inc.into Oil&Gas Company, dated August 26, 1999 (Exhibit 3.1(f) to EOG'sAnnual Report on Form 10-K for the year endedDecember 31, 1999) (SEC FileNo. 001-09743). 3.1(g) - Certificate of Designations of SeriesEJuniorParticipating PreferredStock,datedFebruary 14, 2000 (Exhibit 2toEOG's Registration Statement on Form 8-A, SECFile No. 001-09743, filed February 18, 2000). 3.1(h) - Certificate of Eliminationofthe FixedRateCumulativePerpetual SeniorPreferredStock,Series A, dated September 13, 2000 (Exhibit3.1(j)toEOG's Registration Statement on Form S-3, SECFileNo. 333-46858, filed September28, 2000). 3.1(i) - Certificate of Elimination of the Flexible MoneyMarket CumulativePreferredStock,SeriesC,dated September 13, 2000 (Exhibit3.1(k) to EOG's Registration Statement on Form S-3, SECFile No. 333-46858, filed September28, 2000). 3.1(j) - Certificate of Elimination of the FlexibleMoney Market Cumulative Preferred Stock, Series D, dated February 24, 2005 (Exhibit3.1(k) to EOG'sAnnual ReportonForm10-K for the year endedDecember 31, 2004) (SEC FileNo. 001-09743). 3.1(k) - Amended CertificateofDesignationsofSeries EJunior ParticipatingPreferred Stock, dated March7,2005 (Exhibit 3.1(m)toEOG's Annual Report on Form 10-K for the year endedDecember31, 2007)(SECFile No. 001-09743). 3.1(l) - Certificate of Amendment of RestatedCertificateofIncorporation, dated May 3, 2005 (Exhibit3.1(l) to EOG's Quarterly Report on Form 10-Q for the quarter endedJune30, 2005)(SECFile No. 001-09743). 3.1(m) - Certificate of EliminationofFixed Rate CumulativePerpetual Senior PreferredStock,SeriesB,dated March6,2008 (Exhibit3.1 to EOG's Current Report on Form 8-K, filed March6,2008) (SEC FileNo. 001-09743). 3.1(n) - Certificate of Amendment of Restated Certificate of Incorporation, dated April 28, 2017 (Exhibit 3.1 to EOG's Current Report on Form 8-K, filed May2,2017) (SEC FileNo. 001-09743). 3.2 - Bylaws, dated August 23, 1989, as amendedand restated effective as of September22, 2015 (Exhibit 3.1 to EOG's Current Report on Form 8-K, filed September28, 2015) (SECFileNo. 001-09743). - Description of Securities RegisteredUnderSection 12 of the Securities Exchange Actof1934 (Exhibit4.1 4.1 to EOG'sAnnualReport on Form 10-K for the yearended December 31, 2019) (SECFileNo. 001-09743). 4.2 - Specimen of Certificateevidencing EOG'sCommon Stock(Exhibit3.3 to EOG's Annual Report on Form 10-K for the yearendedDecember 31, 1999) (SEC FileNo. 001-09743). 4.3 -Indenture, dated as of September 1, 1991, between Enron Oil &Gas Company (predecessor to EOG) and The Bank of NewYork Mellon Trust Company,N.A.(as successor in interest to JPMorgan Chase Bank, N.A. (formerly, TexasCommerce Bank National Association)), as Trustee (Exhibit 4(a) to EOG's Registration StatementonFormS-3, SEC FileNo. 33-42640, filed in paperformatonSeptember 6, 1991).

E-1 Exhibit Number Description #4.4(a) -Certificate, dated April3,1998, of the Senior Vice President andChief FinancialOfficerofEnron Oil & Gas Company (predecessor to EOG) establishing the terms of the 6.65% Notes due April 1, 2028 of Enron Oil &Gas Company. #4.4(b) -Global Note with respecttothe 6.65% Notesdue April1,2028ofEnron Oil&Gas Company (predecessor to EOG). 4.5-Indenture, dated as of May 18, 2009, betweenEOG and Wells FargoBank, National Association,as Trustee (Exhibit 4.9 to EOG's Registration StatementonFormS-3, SEC File No. 333-159301, filed May 18, 2009). 4.6(a) - Officers' CertificateEstablishing 2.500% Senior Notes due 2016, 4.100% Senior Notes due 2021 and Floating Rate Senior Notes due 2014 of EOG, datedNovember 23, 2010 (Exhibit 4.2 to EOG's Current Report on Form 8-K, filed November24, 2010) (SECFileNo. 001-09743). 4.6(b) - Form of GlobalNotewithrespect to the 4.100% Senior Notes due 2021 of EOG (Exhibit 4.4 to EOG's Current Report on Form 8-K, filedNovember 24, 2010) (SECFile No. 001-09743). 4.7(a) - Officers' CertificateEstablishing 2.625% Senior Notesdue 2023 of EOG, dated September 10,2012 (Exhibit 4.2 to EOG'sCurrent Report on Form 8-K, filed September11, 2012) (SEC FileNo. 001-09743). 4.7(b) - Form of GlobalNotewithrespect to the 2.625% Senior Notes due 2023 of EOG (Exhibit 4.3 to EOG's Current Report on Form 8-K, filedSeptember 11,2012) (SEC File No. 001-09743).

4.8(a) - Officers' Certificate Establishing3.15% Senior Notes due 2025 and 3.90% Senior Notes due 2035 of EOG, dated March 17, 2015 (Exhibit4.2 to EOG's Current Report on Form 8-K, filedMarch 19, 2015) (SECFile No.001-09743). 4.8(b) - Form of GlobalNote with respecttothe 3.15% Senior Notes due 2025 of EOG (Exhibit 4.3 to EOG's Current Report on Form 8-K, filedMarch19, 2015) (SEC FileNo. 001-09743). 4.8(c) - Form of GlobalNote with respecttothe 3.90% Senior Notes due 2035 of EOG (Exhibit 4.4 to EOG's Current Report on Form 8-K, filedMarch19, 2015) (SEC FileNo. 001-09743). 4.9(a) - Officers' CertificateEstablishing 4.15% Senior Notesdue 2026 and 5.10% Senior Notes due 2036 of EOG, dated January 14, 2016 (Exhibit 4.2 to EOG's Current Report on Form 8-K, filedJanuary 15, 2016) (SEC FileNo. 001-09743). 4.9(b) - Form of GlobalNote with respecttothe 4.15% Senior Notes due 2026 of EOG (Exhibit 4.3 to EOG's Current Report on Form 8-K, filedJanuary 15, 2016) (SEC File No. 001-09743). 4.9(c) - Form of GlobalNote with respecttothe 5.10% Senior Notes due 2036 of EOG (Exhibit 4.4 to EOG's Current Report on Form 8-K, filedJanuary 15, 2016) (SEC File No. 001-09743). 4.10(a) - Officers' CertificateEstablishing 4.375% Senior Notesdue 2030 and 4.950% Senior Notes due 2050 of EOG, dated April 14, 2020 (Exhibit 4.2 to EOG's Current Report on Form 8-K, filed April 14, 2020) (SEC FileNo. 001-09743). 4.10(b) - Form of Global Note with respecttothe 4.375% Senior Notesdue 2030 of EOG (included in Exhibit 4.10(a)). 4.10(c) - Form of Global Note with respecttothe 4.950% Senior Notesdue 2050 of EOG (included in Exhibit 4.10(a)).

10.1(a)+ - Amended andRestatedEOG Resources, Inc. 2008 Omnibus Equity CompensationPlan, effective as of May 2, 2013 (Exhibit 4.4 to EOG's Registration Statement on Form S-8,SEC File No. 333-188352, filed May 3, 2013). 10.1(b)+ - Form of Restricted Stock Award Agreementfor Amendedand Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (applicabletograntsmadeprior to September25, 2017) (Exhibit 4.5 to EOG'sRegistration StatementonForm S-8, SECFileNo. 333-188352,filed May3,2013). 10.1(c)+ - Form of Restricted Stock Award Agreementfor Amendedand Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (applicable to grants made on or after September25, 2017 and prior to September 27, 2018) (Exhibit10.1toEOG's Current Report on Form 8-K, filed September29, 2017) (SEC FileNo. 001-09743).

E-2 Exhibit Number Description 10.1(d)+ - Form of Restricted Stock Award Agreementfor Amendedand Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (applicable to grants made effective September 27,2018 andprior to September 28, 2020) (Exhibit 10.1 to EOG's Quarterly Report on Form 10-Q for the quarterended September 30, 2018) (SECFileNo. 001-09743). 10.1(e)+ - Form of Restricted Stock Award Agreementfor Amendedand Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (applicable to grants made effective September 28, 2020 and subsequent grants) (Exhibit 10.1 to EOG'sQuarterly Report on Form 10-Q for the quarterended September 30, 2020) (SEC File No. 001-09743). 10.1(f)+ - Form of Restricted StockUnit AwardAgreement for Amendedand RestatedEOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (applicabletograntsmadeprior to September25, 2017) (Exhibit 4.6 to EOG'sRegistration StatementonForm S-8, SECFileNo. 333-188352,filed May3,2013).

10.1(g)+ - Form of Restricted StockUnit AwardAgreement for Amendedand RestatedEOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (applicable to grants made on or after September25, 2017 and prior to September 27, 2018) (Exhibit10.2toEOG's Current Report on Form 8-K, filed September29, 2017) (SEC FileNo. 001-09743). 10.1(h)+ Form of Restricted StockUnit AwardAgreement for Amendedand RestatedEOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (applicable to grants made effective September 27,2018 andprior to September 28, 2020) (Exhibit 10.2 to EOG's Quarterly Report on Form 10-Q for the quarterended September 30, 2018) (SECFileNo. 001-09743). 10.1(i)+ - Form of Restricted StockUnit AwardAgreement for Amendedand RestatedEOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (applicable to grants made effective September 28, 2020 and subsequent grants) (Exhibit 10.2 to EOG'sQuarterly Report on Form 10-Q for the quarterended September 30, 2020) (SEC File No. 001-09743). 10.1(j)+ - Form of Stock-Settled Stock AppreciationRight Agreement for Amendedand Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan(applicabletograntsmadeprior to September25, 2017) (Exhibit 4.7 to EOG'sRegistrationStatement on Form S-8, SECFile No.333-188352, filedMay 3, 2013). 10.1(k)+ - Form of Stock-Settled Stock AppreciationRight Agreement for Amendedand Restated EOG Resources, Inc. 2008 Omnibus Equity CompensationPlan (applicable to grantsmadeeffective September 25,2017 and prior to September28, 2020) (Exhibit 10.4 to EOG's Current Report on Form 8-K, filed September 29, 2017) (SEC FileNo. 001-09743). 10.1(l)+ - Form of Stock-Settled Stock AppreciationRight Agreement for Amendedand Restated EOG Resources, Inc. 2008 Omnibus Equity CompensationPlan (applicable to grantsmadeeffective September 28,2020 and subsequent grants) (Exhibit 10.3 to EOG'sQuarterly Report on Form 10-Q for the quarterended September 30, 2020) (SEC File No. 001-09743). 10.1(m)+ - Form of PerformanceUnitAward Agreement for Amendedand RestatedEOG Resources,Inc.2008 Omnibus Equity Compensation Plan (applicabletograntsmadeprior to September22, 2014) (Exhibit 4.8 to EOG'sRegistration StatementonForm S-8, SECFileNo. 333-188352,filed May3,2013). 10.1(n)+ - Form of PerformanceUnitAward Agreement for Amendedand RestatedEOG Resources,Inc.2008 Omnibus Equity Compensation Plan (applicable to grants made on or after September22, 2014 and prior to September 27, 2016) (Exhibit 10.1 to EOG's Quarterly Report on Form 10-Q for the quarterended September 30, 2014) (SECFileNo. 001-09743).

10.1(o)+ - Form of PerformanceUnitAward Agreement for Amendedand RestatedEOG Resources,Inc.2008 Omnibus Equity Compensation Plan (applicable to grants made on or after September27, 2016 and prior to September 25, 2017) (Exhibit 10.1 to EOG's Quarterly Report on Form 10-Q for the quarterended September 30, 2016) (SECFileNo. 001-09743). 10.1(p)+ - Form of PerformanceUnitAward Agreement for Amendedand RestatedEOG Resources,Inc.2008 Omnibus Equity CompensationPlan (applicable only to grants made effective December 13, 2016) (Exhibit 10.1 to EOG'sCurrent Report on Form 8-K, filed December19, 2016) (SEC FileNo. 001-09743). 10.1(q)+ - Form of PerformanceUnitAward Agreement for Amendedand RestatedEOG Resources,Inc.2008 Omnibus Equity Compensation Plan (applicable to grants made on or after September25, 2017 and prior to September 27, 2018) (Exhibit10.3toEOG's Current Report on Form 8-K, filed September29, 2017) (SEC FileNo. 001-09743).

E-3 Exhibit Number Description 10.1(r)+ - Form of PerformanceUnitAward Agreement for Amendedand RestatedEOG Resources,Inc.2008 Omnibus Equity Compensation Plan (applicable to grants made effective September 27,2018 andprior to September 26, 2019) (Exhibit 10.3 to EOG's Quarterly Report on Form 10-Q for the quarterended September 30, 2018) (SECFileNo. 001-09743). 10.1(s)+ - Form of PerformanceUnitAward Agreement for Amendedand RestatedEOG Resources,Inc.2008 Omnibus Equity Compensation Plan (applicable to grants made effective September 26,2019 andprior to September 28, 2020) (Exhibit 10.1 to EOG's Quarterly Report on Form 10-Q for the quarterended September 30, 2019) (SECFileNo. 001-09743). 10.1(t)+ - Form of PerformanceUnitAward Agreement for Amendedand RestatedEOG Resources,Inc.2008 Omnibus Equity Compensation Plan (applicable to grants made effective September 28, 2020 and subsequent grants) (Exhibit 10.4 to EOG'sQuarterly Report on Form 10-Q for the quarterended September 30, 2020) (SEC File No. 001-09743). *10.1(u)+ - Form of PerformanceUnitAward Agreement for Amendedand RestatedEOG Resources,Inc.2008 Omnibus Equity CompensationPlan(applicable to grantmadetoEzraY.Yacob effective January 4, 2021). 10.1(v)+ - Form of PerformanceStock Award Agreement for Amendedand Restated EOG Resources, Inc.2008 Omnibus Equity Compensation Plan (Exhibit 4.9toEOG's Registration StatementonForm S-8, SEC File No. 333-188352, filed May3,2013). 10.1(w) - Form of Non-EmployeeDirector Restricted StockUnit Award Agreementfor Amendedand Restated EOG Resources,Inc. 2008 Omnibus Equity Compensation Plan(applicable to grantsmadeprior to May 6, 2019) (Exhibit 4.10 to EOG'sRegistration StatementonFormS-8, SECFile No. 333-188352, filed May3,2013). 10.1(x)-Form of Non-EmployeeDirector Restricted StockUnit Award Agreementfor Amendedand Restated EOG Resources,Inc. 2008 Omnibus Equity CompensationPlan(applicabletogrants made effective May 6, 2019 and subsequent grants) (Exhibit 10.2 to EOG's Quarterly Report on Form 10-Q for the quarter endedJune 30, 2019) (SEC File No. 001-09743). 10.1(y) - Form of Non-EmployeeDirectorStock-Settled Stock AppreciationRightAgreement for Amendedand Restated EOGResources, Inc. 2008 Omnibus Equity Compensation Plan(Exhibit 4.11 to EOG's Registration StatementonFormS-8, SEC FileNo. 333-188352, filed May3,2013). 10.2(a)+ - EOG Resources, Inc.409A DeferredCompensation Plan -Nonqualified SupplementalDeferred CompensationPlan-PlanDocument,effective as of December16, 2008 (Exhibit10.2(a) to EOG's Annual Report on Form 10-K for the yearended December 31,2008) (SEC File No. 001-09743). 10.2(b)+ - EOG Resources, Inc.409A DeferredCompensation Plan -Nonqualified SupplementalDeferred CompensationPlan-Adoption Agreement, originallydatedasofDecember16, 2008 (and as amended through February 24, 2012 (including an amendmenttoItem7thereof, effective January1,2012, with respect to the deferral of restrictedstock units))(Exhibit 10.2(b)toEOG's Annual Report on Form 10-K for the year ended December 31, 2011) (originally filed as Exhibit10.2(b) to EOG's Annual Report on Form 10-K for the yearendedDecember 31, 2008) (SEC FileNo. 001-09743). 10.2(c)+ - FirstAmendment to theEOG Resources, Inc. 409A DeferredCompensation Plan, effective as of January 1, 2013 (Exhibit 10.8 to EOG's QuarterlyReportonForm10-Qfor the quarterendedSeptember 30,2013) (SEC FileNo. 001-09743).

10.2(d)+ - Amendment 2tothe EOG Resources, Inc. 409A DeferredCompensation Plan, effective as of January1, 2018 (Exhibit10.3(d) to EOG's AnnualReport on Form 10-K for the yearended December31, 2018) (SEC FileNo. 001-09743). *10.2(e)+ - Third Amendment to the EOGResources, Inc. 409A Deferred Compensation Plan, effective as of December 17, 2020. 10.2(f)+ - Amended and Restated 1996 DeferralPlan(Exhibit4.4 to EOG'sRegistrationStatementonFormS-8,SEC File No. 333-84014, filed March 8, 2002).

10.2(g)+ - FirstAmendment to Amendedand Restated 1996 DeferralPlan, effective as of September 10, 2002 (Exhibit 10.9(e) to EOG's AnnualReport on Form 10-K for the year endedDecember31, 2002)(SECFile No. 001-09743). 10.3(a)+ - Change of Control Agreement betweenEOG and WilliamR.Thomas, effective as of January 12, 2011 (Exhibit 10.2 to EOG's QuarterlyReport on Form 10-Q for the quarterendedMarch 31, 2011) (SECFile No. 001-09743).

E-4 Exhibit Number Description 10.3(b)+ - FirstAmendment to ChangeofControl Agreement betweenEOG and WilliamR.Thomas, effective as of September 13, 2011 (Exhibit 10.2 to EOG's Current Report on Form 8-K, filed September 13, 2011) (SEC FileNo. 001-09743).

10.3(c)+ - Second Amendment to Change of Control Agreement between EOG and WilliamR.Thomas, effective as of September4,2013 (Exhibit 10.2 to EOG's Quarterly Report on Form 10-Q for the quarter ended September 30, 2013) (SECFileNo. 001-09743). 10.4(a)+ - Amended and Restated Change of Control Agreement between EOG and Timothy K. Driggers, effective as of June 15, 2005 (Exhibit 99.11 to EOG'sCurrent Report on Form 8-K, filed June 21, 2005) (SEC File No. 001-09743). 10.4(b)+ - FirstAmendment to Amendedand RestatedChange of Control Agreement between EOG and Timothy K. Driggers, effective as of April 30,2009 (Exhibit 10.5 to EOG's QuarterlyReport on Form 10-Q for the quarter ended March 31, 2009) (SECFile No. 001-09743). 10.4(c)+ - Second Amendment to Amendedand Restated ChangeofControl Agreementbetween EOG and Timothy K. Driggers, effective as of September13, 2011 (Exhibit10.4toEOG's CurrentReport on Form 8-K, filed September 13, 2011) (SECFileNo. 001-09743). 10.5(a)+ - Change of Control Agreement by and betweenEOG and MichaelP.Donaldson, effective as of May3, 2012 (Exhibit 10.1 to EOG's QuarterlyReportonForm10-Qfor the quarterendedJune30, 2012) (SEC FileNo. 001-09743). 10.5(b)+ - FirstAmendment to Change of Control Agreement between EOG and MichaelP.Donaldson, effective as of September4,2013 (Exhibit 10.7 to EOG's Quarterly Report on Form 10-Q for the quarter ended September 30, 2013) (SECFileNo. 001-09743). 10.6(a)+ - Change of Control Agreement by and betweenEOG and Lloyd W. Helms, effective as of June 27,2013 (Exhibit 10.9 to EOG's Quarterly Report on Form 10-Q for the quarter endedJune30, 2013)(SECFile No. 001-09743). 10.6(b)+ - FirstAmendment to ChangeofControl Agreement between EOGand Lloyd W. Helms, Jr., effective as of September 4, 2013 (Exhibit 10.4 to EOG's Quarterly Report on Form 10-Q for the quarterended September 30, 2013) (SEC File No. 001-09743). 10.7+ - Change of Control Agreementbyand betweenEOG and EzraY.Yacob, effective as of January 26, 2018 (Exhibit 10.10 to EOG's Annual ReportonForm10-Kfor the year ended December 31, 2017) (SECFile No. 001-09743). 10.8+ - Change of Control Agreementbyand betweenEOG and KennethW.Boedeker, effective as of December 19, 2018 (Exhibit 10.11 to EOG's Annual Report on Form 10-K for the year endedDecember 31, 2018) (SEC FileNo. 001-09743). 10.9(a)+ - EOG Resources, Inc. Change of Control SeverancePlan, as amendedand restated effective as of June 15, 2005 (Exhibit 99.12 to EOG'sCurrent Report on Form 8-K, filedJune21, 2005)(SEC FileNo. 001-09743). 10.9(b)+ - FirstAmendment to the EOG Resources, Inc.Change of Control SeverancePlan, effective as of April 30, 2009 (Exhibit10.6 to EOG's QuarterlyReport on Form 10-Q for the quarterendedMarch 31,2009) (SEC FileNo. 001-09743). 10.10(a)+ - EOG Resources, Inc. Annual Bonus Plan (effective January 1, 2019)(Exhibit 10.1 to EOG's Quarterly Report on Form 10-Q for the quarter endedMarch31, 2019) (SECFileNo. 001-09743). 10.10(b)+ - EOG Resources, Inc. Amendedand Restated Executive Officer AnnualBonus Plan(terminatedeffective January 1, 2019) (Exhibit 10.4 to EOG's QuarterlyReportonForm10-Qfor the quarterended March 31, 2010) (SEC FileNo. 001-09743). 10.11(a)+ - EOG Resources, Inc. EmployeeStock Purchase Plan (AsAmended and Restated Effective January 1, 2018)(Exhibit 4.4(a) to EOG's Registration StatementonFormS-8,SEC File No. 333-224466, filed April 26, 2018). 10.11(b)+ - EOG Resources, Inc. EmployeeStock Purchase Plan (as in effectprior to January 1, 2018) (Exhibit 4.4 to EOG's Registration StatementonForm S-8, SECFileNo. 333-62256, filed June 4, 2001). 10.11(c)+ - Amendment to EOG Resources, Inc. EmployeeStockPurchasePlan, dated effective as of January 1, 2010 (as in effect prior to January 1, 2018) (Exhibit 4.3(b) to EOG's RegistrationStatement on Form S-8, SEC FileNo. 333-166518, filed May4,2010).

E-5 Exhibit Number Description 10.12-Revolving Credit Agreement, dated as of June 27, 2019, among EOG, JPMorganChase Bank, N.A., as Administrative Agent,the financial institutions as bank partiesthereto, and the otherparties thereto(Exhibit 10.1 to EOG'sCurrent Report on Form 8-K, filed July2,2019) (SEC File No. 001-09743). *21 - SubsidiariesofEOG, as of December 31, 2020. *23.1 - Consent of DeGolyerand MacNaughton. *23.2 - Consent of Deloitte&Touche LLP. *24 - Powers of Attorney. *31.1 - Section 302 CertificationofAnnualReport of Principal Executive Officer. *31.2-Section 302 CertificationofAnnualReport of Principal FinancialOfficer. *32.1 - Section 906 CertificationofAnnualReport of Principal Executive Officer. *32.2-Section 906 CertificationofAnnualReport of Principal FinancialOfficer. *95 - Mine SafetyDisclosure Exhibit. *99.1 - Opinion of DeGolyerand MacNaughton, dated January 26, 2021. 101.INS -Inline XBRLInstanceDocument-the instancedocumentdoes not appear in the InteractiveDataFile because its XBRL tagsare embedded within theInline XBRL document. ***101.SCH -Inline XBRL SchemaDocument. ***101.CAL -Inline XBRL Calculation Linkbase Document. ***101.DEF -Inline XBRL Definition Linkbase Document. ***101.LAB -Inline XBRL Label Linkbase Document. ***101.PRE -Inline XBRL Presentation Linkbase Document. 104 -Cover Page InteractiveDataFile(formattedasInline XBRLand contained in Exhibit 101).

*Exhibitsfiled herewith

**AttachedasExhibit 101 to thisreport are the following documents formattedinXBRL (Extensible Business Reporting Language): (i) the Consolidated Statements of Income (Loss) and Comprehensive Income(Loss) for Each of the Three Years in the Period Ended December 31, 2020,(ii) the Consolidated Balance Sheets -December 31, 2020 and 2019, (iii) the Consolidated StatementsofStockholders' Equityfor Each of the Three Years in the Period EndedDecember31, 2020,(iv) the Consolidated StatementsofCash Flows for Each of the Three Years in the Period EndedDecember 31,2020 and (v) the NotestoConsolidated Financial Statements.

+Management contract, compensatory planorarrangement

E-6 SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Actof1934, as amended, the registrant has duly caused this report to be signedonits behalfbythe undersigned, thereuntoduly authorized. EOGRESOURCES,INC. (Registrant)

Date:February 25, 2021 By: /s/ TIMOTHY K. DRIGGERS Timothy K. Driggers Executive Vice President and ChiefFinancial Officer (Principal Financial Officer and Duly Authorized Officer)

Pursuant to the requirements of the SecuritiesExchange Act of 1934, as amended, thisreport has beensignedbelow by the following persons on behalf of the registrant and in the capacities with EOGResources, Inc. indicatedand on the 25th day of February, 2021. Signature Title /s/ WILLIAM R. THOMAS Chairman of theBoard andChief Executive Officer and (William R. Thomas) Director (PrincipalExecutive Officer) /s/ TIMOTHY K. DRIGGERS Executive VicePresident andChief Financial Officer (TimothyK.Driggers)(PrincipalFinancialOfficer) /s/ ANN D. JANSSENSeniorVice President and ChiefAccounting Officer (Ann D. Janssen) (Principal Accounting Officer) *Director (Janet F. Clark) *Director (Charles R. Crisp) *Director (Robert P. Daniels) *Director (JamesC.Day) *Director (C.ChristopherGaut) *Director (Michael T. Kerr) *Director (JulieJ.Robertson) *Director (Donald F. Textor) *By: /s/ MICHAELP.DONALDSON (MichaelP.Donaldson) (Attorney-in-fact for persons indicated) GLOSSARYOFTERMS

$/Bbl Dollars per barrel

$/Mcf Dollars per thousand cubic feet

ATROR After-Tax Rate of Return

Bcf Billion cubic feet

ESG Environmental,Social, Governance

FCF Free Cash Flow

GAAP Generally Accepted Accounting Principles

GHG Greenhouse Gas

MBbl Thousand barrels

MBbld Thousand barrels per day

MMBbl Million barrels

MBoe Thousand barrels of oil equivalent

MBoed Thousand barrels of oil equivalent per day

MMBoe Million barrels of oil equivalent

Mcf Thousand cubic feet

MMcfd Million cubic feet per day

NGLs Natural Gas Liquids

PUDs Proved undeveloped reserves

ROCE Return on Capital Employed

ROE Return on Equity

USD United States dollar

6:1 Gas to liquids conversion rate;crude oil equivalent volumes are determined using aratio of 1.0 barrel of crude oil and condensate or naturalgas liquids to 6.0 thousand cubic feet of natural gas.

125 EOG RESOURCES, INC. Direct After-Tax Rate of Return

The calculation of our direct after-tax rate of return (ATROR) with respect to our capital expenditure program for aparticular play or well is based on the estimated recoverable reserves (“net” to EOG’sinterest) for all wells in such play or such well (as the case may be), the estimated net present value (NPV) of the future net cash flows from such reserves (for which we utilize certain assumptions regarding future commodity prices and operating costs) and our direct net costs incurred in drilling or acquiring (as the case may be) such wells or well (as the case may be). As such, our direct ATROR with respect to our capital expenditures for aparticular play or well cannot be calculatedfrom our consolidated financial statements.

Direct ATROR Based on Cash Flow and Time Value of Money -Estimated future commodity prices and operating costs -Costs incurred to drill, complete and equip awell, including facilities Excludes Indirect Capital -Gathering and Processing and otherMidstream -Land, Seismic, Geological and Geophysical

Payback ~12 Months on 100% Direct ATROR Wells First Five Years ~1/2 Estimated Ultimate Recovery Produced but ~3/4 of NPV Captured

Return on Equity /Return on Capital Employed Based on GAAP Accrual Accounting Includes All Indirect Capital and Growth Capitalfor Infrastructure -Eagle Ford, Bakken, Permian Facilities -Gathering and Processing Includes Legacy Gas Capital and Capital from Mature Wells

126 EOG RESOURCES, INC. ROCE &ROE In millions of USD, except ratio data (Unaudited)

EOG management uses thisinformation for purposes of comparing its financial performance with the financial performance of other companies in the industry.

2019 2018 2017 2016

Net Interest Expense (GAAP) 185 245 274 Less: TaxBenefitImputed (based on 21% for years 2018-2019 and (39) (51) (96) 35% for year 2017) After-Tax Net Interest Expense (Non-GAAP) -(a) 146 194 178

Net Income (GAAP) -(b) 2,735 3,419 2,583

Total Stockholders’ Equity -(c) 21,641 19,364 16,283 13,982

Average Total Stockholders’ Equity *-(d) 20,503 17,824 15,133

Current and Long-Term Debt (GAAP) -(e) 5,175 6,083 6,387 6,986 Less: Cash (2,028) (1,556) (834) (1,600) Net Debt (Non-GAAP) -(f) 3,147 4,527 5,553 5,386

Total Capitalization (GAAP) -(c) +(e) 26,816 25,447 22,670 20,968

Total Capitalization (Non-GAAP) -(c) +(f) 24,788 23,891 21,836 19,368

Average Total Capitalization (Non-GAAP) *-(g) 24,340 22,864 20,602

Return on Capital Employed (ROCE) GAAP Net Income -[(a) +(b)] /(g) 11.8% 15.8% 13.4%

Return on Equity (ROE) GAAP Net Income -(b) /(d) 13.3% 19.2% 17.1%

*Averagefor the current and immediately preceding year

127 EOG RESOURCES, INC. Discretionary Cash Flow and Free Cash Flow In thousands of USD (Unaudited)

EOG management uses thisinformation for purposes of comparing its financial performance with the financial performance of other companies in the industry.

FY 2020 FY 2019 FY 2018 FY 2017

Net Cash Provided by Operating Activities (GAAP) 5,007,783 8,163,180 7,768,608 4,265,336

Adjustments: Exploration Costs (excluding Stock-Based Compensation Expenses) 124,641 113,733 123,986 122,688 Other Non-Current Income Taxes -Net (Payable) Receivable 112,704 238,711148,993 (513,404) Changes in Components of Working Capital and Other Assets and Liabilities Accounts Receivable (466,523) 91,792 368,180 392,131 Inventories (122,647) (90,284) 395,408 174,548 Accounts Payable 795,267 (168,539) (439,347) (324,192) Accrued Taxes Payable 49,096 (40,122) 92,461 63,937 Other Assets (324,521) (358,001) 125,435 658,609 Other Liabilities (8,098) 56,619 (10,949) 89,871 Changes in Components of Working Capital Associated (74,734) 115,061 (301,083) (89,992) with Investing and Financing Activities Discretionary Cash Flow (Non-GAAP) 5,092,968 8,122,150 8,271,692 4,839,532

Discretionary Cash Flow (Non-GAAP) 5,092,968 8,122,150 8,271,692 4,839,532 Less: Total Cash Capital Expenditures Before Acquisitions (Non-GAAP) (a) (3,490,148) (6,234,454) (6,172,950) (4,228,859) Free Cash Flow (Non-GAAP) 1,602,820 1,887,696 2,098,742 610,673

(a) See below reconciliation of Total Expenditures (GAAP) to Total Cash Capital Expenditures Before Acquisitions (Non-GAAP) for the twelve-month periods ended December 31, 2020, 2019, 2018 and 2017:

Total Expenditures (GAAP) 4,113,280 6,900,450 6,706,359 4,612,746 Less: Asset Retirement Costs (117,322) (186,088) (69,699) (55,592) Non-Cash Expenditures of Other Property,Plant and Equipment (61) (2,266) (49,484) - Non-Cash Acquisition Costs of Unproved Properties (196,825) (97,704) (290,542) (255,711) Non-Cash Finance Leases (173,762) --- Acquisition Costs of Proved Properties (135,162) (379,938) (123,684) (72,584) Total Cash Capital Expenditures BeforeAcquisitions (Non-GAAP) 3,490,148 6,234,454 6,172,950 4,228,859

128 OFFICERS AND DIRECTORS (As of February 25, 2021)

DIRECTORS Michael P. Donaldson Charles E. Sheppard Executive Vice President, General Counsel Vice President, Exploration Janet F. Clark (1) and Corporate Secretary Houston, Texas Robert C. Smith Retired Executive Vice President and Timothy K. Driggers Vice President, Drilling Chief Financial Officer, Executive Vice President and Marathon Oil Corporation Chief Financial Officer David J. Streit Vice President, Investor and Public Relations Charles R. Crisp (2) David W. Trice Houston, Texas Executive Vice President and General Steven D. Wentworth Retired President and Chief Executive Officer, Manager,Fort Worth Vice President, Land Coral Energy,LLC Sandeep Bhakhri Robert L. West Robert P. Daniels (3) Senior Vice President and Vice President and Treasurer The Woodlands, Texas Chief Information and Technology Officer Retired Executive Vice President, J. Pat Woods International and Deepwater Exploration, John J. Boyd, III Vice President and General Manager, Anadarko Petroleum Corporation Senior Vice President, Operations International

James C. Day (2) Patricia L. Edwards Heath A. Work Sugar Land, Texas Senior Vice President and Vice President and General Manager, Retired Chairman of the Board and Chief Human Resources Officer Oklahoma City Chief Executive Officer, Noble Corporation plc Ann D. Janssen Jamie L. Hanafy Senior Vice President and ChiefAccounting Controller,Land Administration C. Christopher Gaut (2) Officer Houston, Texas Joseph C. Landry President, Chief Executive Officer and D. Lance Terveen Controller,Operations Accounting Chairman of the Board, Senior Vice President, Marketing Forum Energy Technologies, Inc. Gary Y. Peng Nicholas J. Groves Controller,Financial Reporting (2) Michael T. Kerr Vice President, Safety and Environmental Vero Beach, Florida Amos J. Oelking, III Former Equity Portfolio Manager, Kevin S. Hanzel Deputy Corporate Secretary Capital Group Vice President, Audit (1) Chairperson, Audit Committee; Member, (4) Julie J. Robertson Joseph L. Korenek, Jr. Compensation Committee and Nominating, Houston, Texas Vice President, Business Development Governance and Sustainability Committee Retired Chairman of the Board, President and (2) Member,Audit Committee, Compensation Chief Executive Officer, Reese T. Lantrip Committee and Nominating, Governance and Noble Corporation plc Vice President and General Manager, Sustainability Committee Artesia (3) Chairman, Compensation Committee; Member, Donald F. Textor (5) Audit Committee and Nominating, Governance and Sustainability Committee Locust Valley,New York Philip W. Leimer Former Portfolio Manager, (4) Chairman, Nominating, Governance and Vice President, Tax Dorset Energy Fund Sustainability Committee; Member,Audit Com- mittee and Compensation Committee Jeffrey R. Leitzell (5) Member,Audit Committee, Compensation William R. Thomas Vice President and General Manager,Midland Chairman of the Board and Committee and Nominating, Governance and Chief Executive Officer, Sustainability Committee; 2021 Presiding Kenneth D. Marbach EOG Resources, Inc. Director Vice President and General Manager, Corpus Christi OFFICERS Colleen Marples William R. Thomas Vice President and General Manager, Chairman of the Board and Denver Chief Executive Officer Jill R. Miller Lloyd W. Helms, Jr. Vice President, Engineering and Acquisitions Chief Operating Officer Sammy G. Pickering Ezra Y. Yacob Vice President and General Manager, President

Kenneth W. Boedeker Pamela R. Roth Executive Vice President, Vice President, Government Relations Exploration and Production

129 STOCKHOLDER INFORMATION

Corporate Headquarters 1111 Bagby,Sky Lobby 2 Houston, Texas 77002 P.O. Box 4362 Houston, Texas 77210-4362 (713) 651-7000 Toll Free: (877) 363-EOGR (363-3647) www.eogresources.com

Common Stock Exchange Listing New York Stock Exchange Ticker Symbol: EOG Common Stock Outstanding at December 31, 2020: 583,570,585 shares

Transfer Agent Computershare Trust Company,N.A. Attn: Shareholder Services P.O. Box 505000 Louisville, KY 40233-5000

Overnight Deliveries: Computershare Trust Company,N.A. 462 South 4th Street, Suite 1600 Louisville, KY 40202

Toll Free: (877) 282-1168 Outside U.S.: (781) 575-2879 www.computershare.com Hearing Impaired: TDD (800) 952-9245

2021 Annual Meeting of Stockholders EOG’s2021 Annual Meeting of Stockholders will be held at 2p.m., Central Time, in virtual-only format, via live webcast, on Thursday,April 29, 2021. Information with respect to the annual meeting is contained in the proxy statement made available with this Annual Report to holders of record of EOG Common Stock as of March 5, 2021. This Annual Report is not to be considered apart of EOG’sproxy soliciting material for the annual meeting.

Certifications In 2020, EOG’sChief Executive Officer (CEO) provided to the New York Stock Exchange (NYSE) the annual CEO certification regarding EOG’scompliance with the NYSE’scorporate governance listing standards. In addition, EOG’sCEO (principal executive officer) and EOG’sprincipal financial officer filed with the United States Securities and Exchange Commission (SEC) all certifications required in EOG’sSEC reports for fiscal year 2020.

Additional Information Additional copies of this Annual Report (as well as copies of any of the exhibits to the Form 10-K included herein) are available upon request by calling (877) 363-EOGR (363-3647); by writing EOG’sCorporate Secretary (Michael P. Donaldson) at EOG Resources, Inc., 1111 Bagby,Sky Lobby 2, Houston, Texas 77002; or by visiting the EOG website at www.eogresources.com. Quarterly and annual earnings press release information for EOG and EOG’sSEC filings also can be accessed through EOG’swebsite. Financial analysts and investors who need additional information should visit the EOG website at www.eogresources.com or contact EOG’sInvestor Relations department at (713) 651-7000.

130 EOG OPERATIONS 2020

Production (MMBoe) Year-End Net Proved Reserves (MMBoe) Worldwide 276 3,220 United States 263 3,166 Trinidad and Tobago 11 46 Other International 2 8

Map Legend Areas of Operation Offi ces + Corporate Headquarters

Williston Basin

Powderr River Basin

DJ Basin Denver

Oklahoma City United States AnadarkoAnadadarkokoo Basin NorthwestNorththwest ShelfS BarnettBarnnettt Artesia Shalee Fort Worth UpperUppeU ere Gulff Midland CoastC Houston PermianP i Basinn San Antonio

Eaglee Corpus Christi Ford SouthS TexasTeT

China Trinidad & Tobago

Columbus Basin Sichuan Port of Spain Basin

Chengdu

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