2020 tested EOG like it has never been tested. At the start of the year, the coronavirus pandemic compounded what started as an oil price war, crushing oil demand in a market that was already oversupplied, and drove oil prices to levels the company had not seen in more than 20 years.
EOG generated $1.6 billion of free cash flow* which both paid the dividend and further shored up what was already an industry-leading balance sheet, all while WTI oil prices averaged less than $40 per barrel.
For the third year in a row, EOG increased the dividend at least 30%. The company also announced a new premium natural gas play in South Texas named Dorado. Dorado added 1,250 premium net drilling locations.
EOG more than replaced the inventory drilled throughout the year. The company’s premium inventory had grown to 11,500 net locations by year end, which is more than three and a half times the total since introducing the premium well standard in 2016.
* See reconciliation schedules.
For the third year in a row, EOG delivered on our goal of double-digit returns and double-digit growth in a modest oil price environment – we earned 12% return on capital employed* and increased oil production 14% while WTI oil price averaged $57 per barrel.
For the second year in a row, we increased the dividend rate 31%. We also generated $1.9 billion of free cash flow* that funded $588 million in dividends and the retirement of $900 million of debt.
EOG announced two new premium plays in the Delaware Basin, the Wolfcamp M and Third Bone Spring, adding 1,500 premium net drilling locations and estimated net resource potential of 1.6 BnBoe.
By year-end, EOG’s premium inventory had grown to 10,500 locations, which is more than three times the total since introducing the premium well standard in 2016.
* See reconciliation schedules.
EOG delivered a premium combination in 2018: double digit return and double digit growth.
Return on capital employed was 15%* and we grew oil production 19%.
We earned record net income, generated record free cash flow* and increased the dividend rate 31 percent.
EOG announced two new premium plays in the Powder River Basin, the Mowry and the Niobrara, adding more than 1,500 premium net drilling locations and estimated net resource potential of 1.9 BnBoe.
We published our inaugural Sustainability Report demonstrating our commitment to transparency on the ESG metrics that are most relevant to our business and most important to our shareholders and other stakeholders.
* See reconciliation schedules.
Our premium drilling program delivered 20% U.S. oil production growth.
We proved up 150,000 net acres across two new plays, the Delaware Basin First Bone Spring and Eastern Anadarko Basin Woodford Oil Window.
We replaced almost four times the number of wells completed, adding 2,000 net locations to our growing portfolio of premium oil assets.
By year end, EOG’s premium inventory totaled 8,000 net locations and 7.3 BnBoe of estimated net resource potential in geologic sweet spots across six areas, the Delaware Basin, Eagle Ford, Bakken, Powder River Basin, DJ Basin and Eastern Anadarko Basin.
“Premium” is born. EOG establishes a new standard for capital allocation: the premium well, delivering a minimum 30% direct after-tax rate of return* at $40 crude oil and $2.50 natural gas.
We identified 6,000 premium net drilling locations. That’s more than 10 years of inventory at our 2016 drilling pace.
EOG merges with a historic New Mexico oil and gas company, Yates Petroleum, which adds 260,000 net acres in the core areas of the Delaware Basin and Powder River Basin.
We commercialized the first enhanced oil recovery process, or EOR, in shale.
We added 6x as many new potential well locations as wells drilled during the year.
We increased our estimated net resource potential by 1.6 BnBoe across the Delaware Basin and Bakken through technical innovations in precision targeting and completion design, organic exploration and tactical, bolt-on acquisitions.
We cemented our position as the leading producer in the world-class Eagle Ford play, producing a cumulative 285 million barrels of oil.
Cost control and improved efficiencies were a hallmark of 2015 company operations with cash operating costs down 17%.
We delivered 16% ROE* and 14% ROCE*.
We delivered 31% crude oil production growth and 17% total production growth.
We raised the estimated net resource potential of our premier South Texas Eagle Ford crude oil asset from 2.2 BnBoe to 3.2 BnBoe.
We unveiled four crude oil and combo plays in the Rocky Mountain region with total estimated net resource potential of 400 million barrels of oil.
The board of directors approved a two-for-one stock split in the form of a stock dividend.
*See reconciliation schedules to press release, dated February 18, 2015.
We became the largest producer of oil in the lower 48 states, reaching 300,000 barrels of oil per day of gross operated production.
We grew oil production by 40% and total production by 9%.
Our total proved reserves increased 17% to 2.1 BnBoe.
We announced the Wolfcamp play on the Texas side of the Delaware Basin, adding 800 MMBoe of estimated net resource potential.
Year-over-year non-GAAP earnings per share* grew 50% and crude oil production grew 39%, driven by strong performance from the South Texas Eagle Ford and North Dakota Bakken.
We remain the top crude oil producer in the Eagle Ford, ending the year with production averaging 106,000 barrels of oil equivalent per day.
We opened a crude-by-rail unloading terminal in St. James, Louisiana, giving us expanded access to the Gulf Coast refining markets.
Reached a milestone at our state-of-the-art sand processing plant in Chippewa Falls, Wisconsin, with our first shipment of sand in January. In July, we marked another milestone with the departure of our 500th crude oil unit train from our Stanley, North Dakota, rail terminal, which opened in December 2009.
We increased the cash dividend on the common stock by 6.25% to $0.17 per share.
*See reconciliation schedules to press release, dated February
We reported net income of $1.1 billion compared to $161 million for 2010.
In the U.S., we grew crude oil production more than 60% driven by strong performance from the South Texas Eagle Ford, the Fort Worth Barnett Shale Combo, the Leonard and Wolfcamp Shales in the Permian Basin, and the North Dakota Bakken.
We were the top crude oil producer in the Eagle Ford.
We increased the cash dividend on the common stock by 3% to $0.16 per share.
We announce the South Texas Eagle Ford oil play, our more than half a million-net acre position there, and for the first year in EOG’s history, we generate more revenues from crude oil, condensate and natural gas liquids production than from natural gas production.
In addition to our massive position in the Eagle Ford, EOG’s cadre of liquids-rich assets includes the North Dakota Bakken/Three Forks in the Williston Basin, the Fort Worth Barnett Shale Combo, the Leonard Shale in the Permian Basin, as well as the Denver-Julesberg (DJ) Basin Horizontal Niobrara.
The first train to transport crude oil for EOG Resources arrives in Stroud, Oklahoma on January 3, 2010.
We increased the cash dividend on the common stock by 7%, the 11th increase in 11 years.
We increased total company proved reserves by 2,087 Bcfe to 10.8 Tcfe – 24 percent higher than year–end 2008.
Our total North American liquids production grew 30%, comprised of 23% growth in crude oil and condensate and 48% in natural gas liquids.
The first train to transport crude oil for EOG Resources departed Stanley, North Dakota on December 31, 2009.
We maintained a conservative balance sheet, ending the year with a net debt–to–total capitalization ratio* of 17%.
We increased the cash dividend on the common stock to $0.145 per share, an increase of 7%.
*See reconciliation schedules to press release, dated February 9, 2010.
We more than doubled net income available to common stockholders, earning $2.4 billion compared to $1.1 billion in 2007.
We organically grew overall production 15% and crude oil production 46%, driven primarily by ongoing drilling success in the North Dakota Bakken Play.
Total company proved reserves increased 12% to 8.7 Tcfe.
We organically grew our overall year-over-year production 11% and United States natural gas production 19%.
Crude oil and condensate production grew by 11% while natural gas liquids production increased 31%.
Our proved reserves were approximately 7.7 Tcfe, a 14% increase. From drilling alone, we added 1,534 Bcfe of proved reserves.
Recognizing the company’s strong financial position, Standard and Poor’s upgraded us to A–.
We again increased the cash dividend on the common stock.
Our overall organic year-over-year production increased 9% and United States natural gas production grew 14% driven by our activity in the Fort Worth Basin Barnett Shale, Northeastern Utah Uinta Basin and South Texas Frio and Lobo Plays.
Our proved reserves increased by 607 Bcfe, to 6.8 Tcfe, a 10% increase.
Our results from the Fort Worth Basin Barnett Shale Play exceeded expectations with production at 206 MMcfd, exceeding the original year-end goal of 155 MMcfd.
We reduced long-term debt outstanding to $733 million.
We reported our first full year of production from the UK North Sea and commenced natural gas production to supply feedstock for the M5000 Methanol Plant in Trinidad.
Our proved reserves at year-end were approximately 6.2 Tcfe, an increase of 548 Bcfe.
We executed a two-for-one stock split and increased our annual common stock dividend 33%.
We had approximately 400,000 acres under lease in the Texas Barnett Shale Play with net natural gas production reaching 30 MMcfd during December.
We commenced production from two Southern Gas Basin wells in the United Kingdom North Sea.
We began natural gas sales to the Nitro 2000 (N2000) Ammonia Plant in Trinidad.
Our proved reserves were approximately 5.6 Tcfe, an increase of 430 Bcfe.
We closed the largest acquisition to-date in EOG’s history with the purchase of primarily natural gas properties in southeast Alberta, Canada, for U.S. $320 million.
Our proved reserves were approximately 5.2 Tcfe, an increase of 614 Bcfe.
Our increased reserves replaced 249% of production for a low total company all-in finding cost of $1.28 per Mcfe.
We significantly improved our financial position, reducing our debt-to-total capitalization ratio from 41% to 33% year-end 2002.
In Trinidad, we announced the Parula natural gas discovery, added two new offshore exploration blocks, successfully started up the CNC Ammonia Plant and signed a 25-year extension on the offshore SECC Block.
Our proved reserves increased by 9% to approximately 4.6 Tcfe, replacing 193% of production at a finding cost of $1.06 per Mcfe.
We increased total Canadian production 23% and natural gas production 22%, as compared to 2001.
We reduced the number of EOG shares outstanding by repurchasing approximately 700,000 shares of common stock, net of option exercises, stock plans and other increases.
We delivered a return on common shareholders’ equity of 28.4% for the year.
We replaced 201% of production from all sources at a finding cost of $1.36 per Mcfe.
Our debt-to-total-capitalization ratio, one of the lowest in the industry, improved to 34%.
The common stock dividend increased by $0.02 to $0.16 per share.
Our stock appreciated 211% and we were added to the Standard & Poor’s 500 Index after the close of trading on November 1, 2000.
We were ranked as the third best performer in the Standard and Poor’s 500 Index.
We were the second most active driller in the U.S.
Our total production increased 8.9%.
We signed a 15-year natural gas supply contract with the National Gas Company of Trinidad and Tobago Limited (NGC) to supply an ammonia plant.
The annual common stock dividend increased from $0.12 per share to $0.14 per share.