EOG Resources Reports Second Quarter 2023 Results

HOUSTON, Aug. 3, 2023 /PRNewswire/ -- EOG Resources, Inc. (EOG) today reported second quarter 2023 results. The attached supplemental financial tables and schedules for the reconciliation of non-GAAP measures to GAAP measures and related definitions, along with a related presentation, are also available on EOG's website at http://investors.eogresources.com/investors.

 

Key Financial Results
In millions of USD, except per-share, per-Boe and ratio data
GAAP	2Q 2023	1Q 2023	4Q 2022	3Q 2022	2Q 2022
Total Revenue	5,573	6,044	6,719	7,593	7,407
Net Income	1,553	2,023	2,277	2,854	2,238
Net Income Per Share	2.66	3.45	3.87	4.86	3.81
Net Cash Provided by Operating Activities	2,277	3,255	3,444	4,773	2,048
Total Expenditures	1,664	1,717	1,535	1,410	1,521
Current and Long-Term Debt	3,814	3,820	5,078	5,084	5,091
Cash and Cash Equivalents	4,764	5,018	5,972	5,272	3,073
Debt-to-Total Capitalization	12.7 %	13.1 %	17.0 %	17.6 %	18.6 %
Cash Operating Costs ($/Boe)	10.03	10.59	10.82	10.89	10.12
General and Administrative Costs ($/Boe)	1.61	1.71	1.87	1.92	1.53
Non - GAAP
Adjusted Net Income	1,457	1,578	1,941	2,179	1,614
Adjusted Net Income Per Share	2.49	2.69	3.30	3.71	2.74
CFO before Changes in Working Capital	2,563	2,559	3,091	3,432	2,357
Capital Expenditures	1,521	1,489	1,361	1,166	1,071
Free Cash Flow	1,042	1,070	1,730	2,266	1,286
Net Debt	(950)	(1,198)	(894)	(188)	2,018
Net Debt-to-Total Capitalization	(3.8 %)	(4.9 %)	(3.7 %)	(0.8 %)	8.3 %
Cash Operating Costs ($/Boe)1	10.03	10.59	10.82	10.70	10.12
General and Administrative Costs ($/Boe)1	1.61	1.71	1.87	1.73	1.53

 

Second Quarter Highlights

• Earned adjusted net income of $1.5 billion, or $2.49 per share
• Generated $1.0 billion of free cash flow
• Declared regular quarterly dividend of $0.825 per share
• Repurchased $300 million of shares during the second quarter
• Oil, NGL, and natural gas production above guidance midpoints
• Capital expenditures, per-unit cash operating costs, and per-unit DD&A below guidance midpoints

 

Volumes and Capital Expenditures

		2Q 2023
	2Q 2023	Guidance Midpoint	1Q 2023	4Q 2022	3Q 2022	2Q 2022
Wellhead Volumes
Crude Oil and Condensate (MBod)	476.6	472.6	457.7	465.6	465.1	464.1
Natural Gas Liquids (MBbld)	215.7	212.0	212.2	189.0	209.3	201.9
Natural Gas (MMcfd)	1,668	1,635	1,639	1,527	1,469	1,528
Total Crude Oil Equivalent (MBoed)	970.3	957.1	943.0	909.1	919.2	920.7
Capital Expenditures ($MM)	1,521	1,650	1,489	1,361	1,166	1,071

 

Regular Dividend and Second Quarter Share Repurchases
The Board of Directors today declared a dividend of $0.825 per share on EOG's common stock. The dividend will be payable October 31, 2023, to stockholders of record as of October 17, 2023. The indicated annual rate is $3.30 per share.

During the second quarter, the company repurchased 2.8 million shares for $300 million under its share repurchase authorization, at an average purchase price of approximately $108 per share.

Year-to-date, the company repurchased 5.7 million shares for $610 million under its share repurchase authorization, at an average purchase price of approximately $107 per share. EOG has approximately $4.4 billion remaining on its current share buyback authorization.

 

From Ezra Yacob, Chairman and Chief Executive Officer
"EOG delivered another quarter of exceptional operating performance with production volumes, capital expenditures, and cash operating costs all better than expected. Results through the first half of the year reflect consistent operating execution across our multi-basin portfolio to lower costs and generate free cash flow.

"EOG remains committed to returning cash to our shareholders. We paid our peer-leading regular dividend and repurchased shares with strong free cash flow during the quarter. To date, we have already committed to returning more than 60% of expected free cash flow in 2023 to shareholders, with the potential to return additional cash over the balance of the year.

"Along with strong performance in the Delaware Basin and Eagle Ford, we are pleased by the outstanding progress across our emerging plays. The South Texas Dorado, Southern Powder River Basin, and Ohio Utica Combo are achieving significant operational improvements, driving lower costs and supporting higher returns. EOG is performing better than ever, with the benefits of our multi-basin portfolio providing a clear runway to drive further improvements and value for our shareholders."

 

Second Quarter 2023 Financial Performance

Prices

• Crude oil, NGL, and natural gas prices declined in 2Q compared with 1Q

Volumes

• Total 2Q oil production of 476,600 Bopd was above the midpoint of the guidance range and up 4% from 1Q, reflecting a planned change in activity mix
• NGL and natural gas production were each above the midpoint of the guidance range and up 2% from 1Q
• Total company equivalent production increased 3% from 1Q

Per-Unit Costs

• LOE, transportation, gathering and processing, and G&A costs decreased in 2Q compared with 1Q, while DD&A expenses increased

Hedges

• Mark-to-market hedge gains decreased, lowering GAAP earnings per share in 2Q compared with 1Q
• Lower cash paid to settle hedges partially offset the impact of lower commodity prices on adjusted non-GAAP earnings per share

Free Cash Flow

• Cash flow from operations before changes in working capital was $2.56 billion
• EOG incurred $1.52 billion of capital expenditures
• This resulted in $1.04 billion of free cash flow

Cash Return and Working Capital

• Paid $480 million in regular dividends
• Repurchased $300 million of stock
• Changes in working capital accounted for $540 million of the decrease in cash

 

Second Quarter 2023 Operating Performance

Lease and Well
Per-unit lease and well costs decreased in 2Q compared with 1Q and were below the guidance midpoint primarily due to decreased workovers and fuel-related expenses.

Transportation; Gathering and Processing
Per-unit transportation and G&P costs declined in 2Q and were below the guidance midpoints primarily due to oil transportation optimization, higher in-basin NGL sales, and lower fuel costs.

General and Administrative
Per-unit G&A costs declined in 2Q and were below the guidance midpoint primarily due to lower third-party service expenses.

Depreciation, Depletion and Amortization
Per-unit DD&A costs increased in 2Q compared with 1Q but were below the guidance midpoint due to well mix.

 

Second Quarter 2023 Results vs Guidance
(Unaudited)
See "Endnotes" below for related discussion and definitions.
			2Q 2023
	2Q 2023		Guidance Midpoint	Variance	1Q 2023	4Q 2022	3Q 2022	2Q 2022
Crude Oil and Condensate Volumes (MBod)
United States	476.0		472.0	4.0	457.1	465.1	464.6	463.5
Trinidad	0.6		0.6	0.0	0.6	0.5	0.5	0.6
Other International	0.0		0.0	0.0	0.0	0.0	0.0	0.0
Total	476.6		472.6	4.0	457.7	465.6	465.1	464.1
Natural Gas Liquids Volumes (MBbld)
Total	215.7		212.0	3.7	212.2	189.0	209.3	201.9
Natural Gas Volumes (MMcfd)
United States	1,513		1,490	23	1,475	1,378	1,306	1,324
Trinidad	155		145	10	164	149	163	204
Other International	0		0	0	0	0	0	0
Total	1,668		1,635	33	1,639	1,527	1,469	1,528
Total Crude Oil Equivalent Volumes (MBoed)	970.3		957.1	13.2	943.0	909.1	919.2	920.7
Total MMBoe	88.3		87.1	1.2	84.9	83.6	84.6	83.8
Benchmark Price
Oil (WTI) ($/Bbl)	73.75				76.11	82.63	91.64	108.42
Natural Gas (HH) ($/Mcf)	2.09				3.43	6.27	8.18	7.17
Crude Oil and Condensate - above (below) WTI3 ($/Bbl)
United States	1.23		0.70	0.53	1.16	3.05	4.41	2.84
Trinidad	(8.87)		(9.50)	0.63	(7.13)	(7.42)	(6.66)	(10.13)
Natural Gas Liquids - Realizations as % of WTI
Total	28.3 %		29.0 %	(0.7 %)	33.7 %	34.6 %	39.3 %	39.0 %
Natural Gas - above (below) NYMEX Henry Hub4 ($/Mcf)
United States	(0.02)		0.00	(0.02)	0.04	(0.15)	1.17	0.60
Natural Gas Realizations5 ($/Mcf)
Trinidad	3.45		3.45	0.00	3.87	3.97	7.45	3.42
Total Expenditures (GAAP) ($MM)	1,664				1,717	1,535	1,410	1,521
Capital Expenditures (non-GAAP) ($MM)	1,521		1,650	(129)	1,489	1,361	1,166	1,071
Operating Unit Costs ($/Boe)
Lease and Well	3.94		4.20	(0.26)	4.23	4.23	3.96	3.87
Transportation Costs	2.67		2.85	(0.18)	2.78	2.83	3.04	2.91
Gathering and Processing	1.81		1.90	(0.09)	1.87	1.89	1.97	1.81
General and Administrative (GAAP)	1.61		1.70	(0.09)	1.71	1.87	1.92	1.53
General and Administrative (non-GAAP)1	1.61		1.70	(0.09)	1.71	1.87	1.73	1.53
Cash Operating Costs (GAAP)	10.03		10.65	(0.62)	10.59	10.82	10.89	10.12
Cash Operating Costs (non-GAAP)	10.03		10.65	(0.62)	10.59	10.82	10.70	10.12
Depreciation, Depletion and Amortization	9.81		10.00	(0.19)	9.40	10.50	10.71	10.87
Expenses ($MM)
Exploration and Dry Hole	47		65	(18)	51	48	53	55
Impairment (GAAP)	35				34	142	94	91
Impairment (excluding certain impairments (non-GAAP))6	35		100	(65)	34	111	48	55
Capitalized Interest	8		9	(1)	8	11	11	7
Net Interest	35		34	1	42	42	41	48
TOTI (% of Wellhead Revenue) (GAAP)	7.8 %		8.5 %	(0.7 %)	7.8 %	7.8 %	5.5 %	7.3 %
TOTI (% of Wellhead Revenue) (non-GAAP)1	7.8 %		8.5 %	(0.7 %)	7.8 %	7.8 %	7.4 %	7.3 %
Income Taxes
Effective Rate	21.9 %		21.5 %	0.4 %	22.0 %	20.4 %	22.1 %	22.3 %
Current Tax (Benefit) / Expense ($MM)	241		365	(124)	338	409	481	745

 

 

Third Quarter and Full-Year 2023 Guidance7
(Unaudited)
See "Endnotes" below for related discussion and definitions.
	3Q 2023 Guidance Range			3Q 2023 Midpoint	FY 2023 Guidance Range			FY 2023 Midpoint	2022 Actual	2021 Actual	2020 Actual
Crude Oil and Condensate Volumes (MBod)
United States	467.0	-	478.0	472.5	471.0	-	476.0	473.5	460.7	443.4	408.1
Trinidad	0.2	-	0.6	0.4	0.3	-	0.5	0.4	0.6	1.5	1.0
Other International	0.0	-	0.0	0.0	0.0	-	0.0	0.0	0.0	0.1	0.1
Total	467.2	-	478.6	472.9	471.3	-	476.5	473.9	461.3	445.0	409.2
Natural Gas Liquids Volumes (MBbld)
Total	218.0	-	228.0	223.0	219.0	-	225.0	222.0	197.7	144.5	136.0
Natural Gas Volumes (MMcfd)
United States	1,500	-	1,560	1,530	1,510	-	1,570	1,540	1,315	1,210	1,040
Trinidad	115	-	145	130	140	-	170	155	180	217	180
Other International	0	-	0	0	0	-	0	0	0	9	32
Total	1,615	-	1,705	1,660	1,650	-	1,740	1,695	1,495	1,436	1,252
Crude Oil Equivalent Volumes (MBoed)
United States	935.0	-	966.0	950.5	941.7	-	962.7	952.2	877.5	789.6	717.5
Trinidad	19.4	-	24.8	22.1	23.6	-	28.8	26.2	30.7	37.7	30.9
Other International	0.0	-	0.0	0.0	0.0	-	0.0	0.0	0.0	1.6	5.4
Total	954.4	-	990.8	972.6	965.3	-	991.5	978.4	908.2	828.9	753.8
Benchmark Price
Oil (WTI) ($/Bbl)									94.23	67.96	39.40
Natural Gas (HH) ($/Mcf)									6.64	3.85	2.08
Crude Oil and Condensate - above (below) WTI3 ($/Bbl)
United States	0.50	-	1.50	1.00	0.50	-	1.50	1.00	2.99	0.58	(0.75)
Trinidad	(11.00)	-	(9.00)	(10.00)	(9.50)	-	(8.50)	(9.00)	(8.07)	(11.70)	(9.20)
Natural Gas Liquids - Realizations as % of WTI
Total	23.0 %	-	33.0 %	28.0 %	27.0 %	-	33.0 %	30.0 %	39.0 %	50.5 %	34.0 %
Natural Gas - above (below) NYMEX Henry Hub4 ($/Mcf)
United States	(0.30)	-	0.20	(0.05)	(0.50)	-	0.50	0.00	0.63	1.03	(0.47)
Natural Gas Realizations5 ($/Mcf)
Trinidad	3.00	-	3.70	3.35	3.30	-	3.80	3.55	4.43	3.40	2.57
Total Expenditures (GAAP) ($MM)									5,610	4,255	4,113
Capital Expenditures8 (non-GAAP) ($MM)	1,560	-	1,760	1,660	5,800	-	6,200	6,000	4,607	3,755	3,344
Operating Unit Costs ($/Boe)
Lease and Well	3.90	-	4.50	4.20	4.00	-	4.30	4.15	4.02	3.75	3.85
Transportation Costs	2.55	-	2.85	2.70	2.70	-	2.80	2.75	2.91	2.85	2.66
Gathering and Processing	1.80	-	2.00	1.90	1.85	-	1.95	1.90	1.87	1.85	1.66
General and Administrative (GAAP)	1.75	-	2.05	1.90	1.65	-	1.80	1.73	1.72	1.69	1.75
General and Administrative (non-GAAP)1									1.67	1.69	1.75
Cash Operating Costs (GAAP)	10.00	-	11.40	10.70	10.20	-	10.85	10.53	10.52	10.14	9.92
Cash Operating Costs (non-GAAP)									10.47	10.14	9.92
Depreciation, Depletion and Amortization	9.40	-	10.40	9.90	9.60	-	10.20	9.90	10.69	12.07	12.32
Expenses ($MM)
Exploration and Dry Hole	45	-	85	65	170	-	230	200	204	225	159
Impairment (GAAP)									382	376	2,100
Impairment (excluding certain impairments (non GAAP))6	65	-	135	100	200	-	340	270	269	361	232
Capitalized Interest	8	-	12	10	32	-	36	34	36	33	31
Net Interest	32	-	36	34	142	-	146	144	179	178	205
TOTI (% of Wellhead Revenue) (GAAP)	7.5 %	-	9.5 %	8.5 %	7.0 %	-	9.0 %	8.0 %	7.0 %	6.8 %	6.6 %
TOTI (% of Wellhead Revenue) (non-GAAP)1									7.5 %	6.8 %	6.6 %
Income Taxes
Effective Rate	19.0 %	-	24.0 %	21.5 %	19.0 %	-	24.0 %	21.5 %	21.7 %	21.4 %	18.2 %
Current Tax (Benefit) / Expense ($MM)	295	-	395	345	1,130	-	1,330	1,230	2,208	1,393	(61)

 

Second Quarter 2023 Results Webcast
Friday, August 4, 2023, 9:00 a.m. Central time (10:00 a.m. Eastern time)
Webcast will be available on EOG's website for one year.
http://investors.eogresources.com/Investors

About EOG
EOG Resources, Inc. (NYSE: EOG) is one of the largest crude oil and natural gas exploration and production companies in the United States with proved reserves in the United States and Trinidad. To learn more visit www.eogresources.com.

Investor Contacts
David Streit 713-571-4902
Neel Panchal 713-571-4884
Shelby O'Connor 713-571-4560

Media Contact
Kimberly Ehmer 713-571-4676

Endnotes
1)	Third quarter 2022 TOTI (% of Wellhead Revenue) (non-GAAP) and General and Administrative Costs (non-GAAP) exclude a state severance tax refund and related consulting fees, respectively, as reflected in the accompanying Adjusted Net Income (Loss) reconciliation schedule.
2)	Includes gathering, processing and marketing revenue, gains (losses) on asset dispositions, other revenue, exploration, dry hole, impairments and marketing costs, taxes other than income, other income (expense), interest expense and the impact of changes in the effective income tax rate.
3)	EOG bases United States and Trinidad crude oil and condensate price differentials upon the West Texas Intermediate crude oil price at Cushing, Oklahoma, using the simple average of the NYMEX settlement prices for each trading day within the applicable calendar month.
4)	EOG bases United States natural gas price differentials upon the natural gas price at Henry Hub, Louisiana, using the NYMEX Last Day Settle price for each of the applicable months.
5)	The third quarter and full-year 2022 realized natural gas price for Trinidad includes a one-time pricing adjustment of $3.37/Mcf and $0.76/Mcf, respectively, for prior-period production following a contract amendment with the National Gas Company of Trinidad and Tobago Limited (NGC).
6)	In general, EOG excludes impairments which are (i) attributable to declines in commodity prices, (ii) related to sales of certain oil and gas properties or (iii) the result of certain other events or decisions (e.g., a periodic review of EOG's oil and gas properties or other assets). EOG believes excluding these impairments from total impairment costs is appropriate and provides useful information to investors, as such impairments were caused by factors outside of EOG's control (versus, for example, impairments that are due to EOG's proved oil and gas properties not being as productive as it originally estimated).
7)	The forecast items for the third quarter and full year 2023 set forth above for EOG are based on currently available information and expectations as of the date of this press release. EOG undertakes no obligation, other than as required by applicable law, to update or revise this forecast, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise. This forecast, which should be read in conjunction with this press release and EOG's related Current Report on Form 8-K filing, replaces and supersedes any previously issued guidance or forecast.
8)	The forecast includes expenditures for Exploration and Development Drilling, Facilities, Leasehold Acquisitions, Capitalized Interest, Dry Hole Costs and Other Property, Plant and Equipment. The forecast excludes Property Acquisitions, Asset Retirement Costs, Non-Cash Exchanges and Transactions and exploration costs incurred as operating expenses.

 

Glossary
Acq	Acquisitions
ATROR	After-tax rate of return
Bbl	Barrel
Bn	Billion
Boe	Barrels of oil equivalent
Bopd	Barrels of oil per day
CAGR	Compound annual growth rate
Capex	Capital expenditures
CFO	Cash flow provided by operating activities before changes in working capital
CO2e	Carbon dioxide equivalent
DD&A	Depreciation, Depletion and Amortization
Disc	Discoveries
Divest	Divestitures
EPS	Earnings per share
Ext	Extensions
G&A	General and administrative expense
G&P	Gathering and processing expense
GHG	Greenhouse gas
HH	Henry Hub
LOE	Lease operating expense, or lease and well expense
MBbld	Thousand barrels of liquids per day
MBod	Thousand barrels of oil per day
MBoe	Thousand barrels of oil equivalent
MBoed	Thousand barrels of oil equivalent per day
Mcf	Thousand cubic feet of natural gas
MMBoe	Million barrels of oil equivalent
MMcfd	Million cubic feet of natural gas per day
NGLs	Natural gas liquids
NYMEX	U.S. New York Mercantile Exchange
OTP	Other than price
QoQ	Quarter over quarter
TOTI	Taxes other than income
Trans	Transportation expense
USD	United States dollar
WTI	West Texas Intermediate
YoY	Year over year
$MM	Million United States dollars
$/Bbl	U.S. Dollars per barrel
$/Boe	U.S. Dollars per barrel of oil equivalent
$/Mcf	U.S. Dollars per thousand cubic feet

 

This press release may include forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 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 and rates of return, budgets, reserves,   levels of production, capital expenditures, costs and asset sales, statements regarding future commodity prices and statements regarding the plans and objectives of EOG's management for future operations, are forward-looking statements.  EOG typically uses words such as "expect," "anticipate,"  "estimate," "project," "strategy," "intend," "plan," "target," "aims," "ambition," "initiative," "goal," "may," "will," "focused on," "should" and "believe" or    the negative of those terms or other variations or comparable terminology to identify its forward-looking statements. In particular, statements, express or implied, concerning EOG's future financial or operating results and returns or EOG's ability to replace or increase reserves, increase production, generate returns and rates of return, replace or increase drilling locations, reduce or otherwise control drilling, completion and operating costs and capital expenditures, generate cash flows, pay down or refinance indebtedness, achieve, reach or otherwise meet initiatives, plans, goals, ambitions or targets    with respect to emissions, other environmental matters, safety matters or other ESG (environmental/social/governance) matters, or pay and/or increase dividends are forward-looking statements. Forward-looking statements are not guarantees of performance. Although EOG believes the expectations reflected in its forward-looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that such assumptions are accurate or will prove to have been correct or that any of such expectations will be achieved (in full or at all) or will be achieved on the expected or anticipated timelines. Moreover, EOG's forward-looking statements may be affected by known, unknown or currently unforeseen risks, events or circumstances that may be outside EOG's control. Furthermore, this press release and any accompanying disclosures may include or reference certain forward-looking, non-GAAP financial measures, such as free cash flow and cash flow from operations before changes in working capital, and certain related estimates regarding future performance, results and financial position. Because we provide these measures on a forward-looking basis, we cannot reliably  or reasonably predict certain of the necessary components of the most directly comparable forward-looking GAAP measures, such as future changes in working capital. Accordingly, we are unable to present a quantitative reconciliation of such forward-looking, non-GAAP financial measures to the respective most directly comparable forward-looking GAAP financial measures. Management believes these forward-looking, non-GAAP measures may be a useful   tool for the investment community in comparing EOG's forecasted financial performance to the forecasted financial performance of other companies in the industry. Any such forward-looking measures and estimates are intended to be illustrative only and are not intended to reflect the results that EOG will necessarily achieve for the period(s) presented; EOG's actual results may differ materially from such measures and estimates. Important factors that could cause EOG's actual results to differ materially from the expectations reflected in EOG's forward-looking statements include, among others:

• the timing, extent and duration of changes in prices for, supplies of, and demand for, crude oil and condensate, natural gas liquids (NGLs), natural gas and related commodities;
• the extent to which EOG is successful in its efforts to acquire or discover additional reserves;
• the extent to which EOG is successful in its efforts to (i) economically develop its acreage in, (ii) produce reserves and achieve anticipated production levels and rates of return from, (iii) decrease or otherwise control its drilling, completion and operating costs and capital expenditures related to, and (iv) maximize reserve recovery from, its existing and future crude oil and natural gas exploration and development projects and associated potential and existing drilling locations;
• the success of EOG's cost-mitigation initiatives and actions in offsetting the impact of inflationary pressures on EOG's operating costs and capital expenditures;
• the extent to which EOG is successful in its efforts to market its production of crude oil and condensate, NGLs and natural gas;
• security threats, including cybersecurity threats and disruptions to our business and operations from breaches of our information technology systems, physical breaches of our facilities and other infrastructure or breaches of the information technology systems, facilities and infrastructure of third parties with which we transact business;
• the availability, proximity and capacity of, and costs associated with, appropriate gathering, processing, compression, storage, transportation, refining, and export facilities;
• the availability, cost, terms and timing of issuance or execution of mineral licenses and leases and governmental and other permits and rights-of- way, and EOG's ability to retain mineral licenses and leases;
• the impact of, and changes in, government policies, laws and regulations, including climate change-related regulations, policies and initiatives (for example, with respect to air emissions); tax laws and regulations (including, but not limited to, carbon tax and emissions-related legislation); environmental, health and safety laws and regulations relating to disposal of produced water, drilling fluids and other wastes, hydraulic fracturing and access to and use of water; laws and regulations affecting the leasing of acreage and permitting for oil and gas drilling and the calculation of royalty payments in respect of oil and gas production; laws and regulations imposing additional permitting and disclosure requirements, additional operating restrictions and conditions or restrictions on drilling and completion operations and on the transportation of crude oil, NGLs and natural gas; laws and regulations with respect to financial derivatives and hedging activities; and laws and regulations with respect to the import and  export of crude oil, natural gas and related commodities;
• the impact of climate change-related policies and initiatives at the corporate and/or investor community levels and other potential developments related to climate change, such as (but not limited to) changes in consumer and industrial/commercial behavior, preferences and attitudes with respect to the generation and consumption of energy; increased availability of, and increased consumer and industrial/commercial demand for, competing energy sources (including alternative energy sources); technological advances with respect to the generation, transmission, storage and consumption of energy; alternative fuel requirements; energy conservation measures and emissions-related legislation; decreased demand for, and availability of, services and facilities related to the exploration for, and production of, crude oil, NGLs and natural gas; and negative perceptions of  the oil and gas industry and, in turn, reputational risks associated with the exploration for, and production of, crude oil, NGLs and natural gas;
• continuing political and social concerns relating to climate change and the greater potential for shareholder activism, governmental inquiries and enforcement actions and litigation and the resulting expenses and potential disruption to EOG's day-to-day operations;
• the extent to which EOG is able to successfully and economically develop, implement and carry out its emissions and other ESG-related initiatives and achieve its related targets and initiatives;
• EOG's ability to effectively integrate acquired crude oil and natural gas properties into its operations, identify and resolve existing and potential issues with respect to such properties and accurately estimate reserves, production, drilling, completion and operating costs and capital expenditures with respect to such properties;
• the extent to which EOG's third-party-operated crude oil and natural gas properties are operated successfully, economically and in compliance with applicable laws and regulations;
• competition in the oil and gas exploration and production industry for the acquisition of licenses, leases and properties;
• the availability and cost of, and competition in the oil and gas exploration and production industry for, employees, labor and other personnel, facilities, equipment, materials (such as water, sand, fuel and tubulars) and services;
• the accuracy of reserve estimates, which by their nature involve the exercise of professional judgment and may therefore be imprecise;
• weather, including its impact on crude oil and natural gas demand, and weather-related delays in drilling and in the installation and operation (by EOG or third parties) of production, gathering, processing, refining, compression, storage, transportation, and export facilities;
• the ability of EOG's customers and other contractual counterparties to satisfy their obligations to EOG and, related thereto, to access the credit and capital markets to obtain financing needed to satisfy their obligations to EOG;
• EOG's ability to access the commercial paper market and other credit and capital markets to obtain financing on terms it deems acceptable, if at all, and to otherwise satisfy its capital expenditure requirements;
• the extent to which EOG is successful in its completion of planned asset dispositions;
• the extent and effect of any hedging activities engaged in by EOG;
• the timing and extent of changes in foreign currency exchange rates, interest rates, inflation rates, global and domestic financial market conditions and global and domestic general economic conditions;
• the duration and economic and financial impact of epidemics, pandemics or other public health issues;
• geopolitical factors and political conditions and developments around the world (such as the imposition of tariffs or trade or other economic sanctions, political instability and armed conflict), including in the areas in which EOG operates;
• the extent to which EOG incurs uninsured losses and liabilities or losses and liabilities in excess of its insurance coverage;
• acts of war and terrorism and responses to these acts; and
• the other factors described under ITEM 1A, Risk Factors of EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2022 and any updates to those factors set forth in EOG's subsequent Quarterly Reports on Form 10-Q or Current Reports on Form 8-K.

In light of these risks, uncertainties and assumptions, the events anticipated by EOG's forward-looking statements may not occur, and, if any of such events do, we may not have anticipated the timing of their occurrence or the duration or extent of their impact on our actual results. Accordingly, you should not place any undue reliance on any of EOG's forward-looking statements. EOG's forward-looking statements speak only as of the date made, and EOG undertakes no obligation, other than as required by applicable law, to update or revise its forward-looking statements, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise.

The United States Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to disclose not only "proved" reserves (i.e., quantities of oil and gas that are estimated to be recoverable with a high degree of confidence), but also "probable" reserves (i.e., quantities  of oil and gas that are as likely as not to be recovered) as well as "possible" reserves (i.e., additional quantities of oil and gas that might be recovered, but with a lower probability than probable reserves). Statements of reserves are only estimates and may not correspond to the ultimate quantities of oil and   gas recovered. Any reserve or resource estimates provided in this press release that are not specifically designated as being estimates of proved reserves may include "potential" reserves, "resource potential" and/or other estimated reserves or estimated resources not necessarily calculated in accordance with, or contemplated by, the SEC's latest reserve reporting guidelines. Investors are urged to consider closely the disclosure in EOG's Annual Report on  Form 10-K for the fiscal year ended December 31, 2022, available from EOG at P.O. Box 4362, Houston, Texas 77210-4362 (Attn: Investor Relations). You can also obtain this report from the SEC by calling 1-800-SEC-0330 or from the SEC's website at www.sec.gov. In addition, reconciliation schedules and  definitions for non-GAAP financial measures can be found on the EOG website at www.eogresources.com.

 

Income Statements
In millions of USD, except share data (in millions) and per share data (Unaudited)
	2022						2023
	1st Qtr	2nd Qtr	3rd Qtr	4th Qtr	Year		1st Qtr	2nd Qtr	3rd Qtr	4th Qtr	YTD
Operating Revenues and Other
Crude Oil and Condensate	3,889	4,699	4,109	3,670	16,367		3,182	3,252			6,434
Natural Gas Liquids	681	777	693	497	2,648		490	409			899
Natural Gas	716	1,000	1,235	830	3,781		517	334			851
Gains (Losses) on Mark-to-Market      Financial Commodity Derivative      Contracts, Net	(2,820)	(1,377)	(18)	233	(3,982)		376	101			477
Gathering, Processing and Marketing	1,469	2,169	1,561	1,497	6,696		1,390	1,465			2,855
Gains (Losses) on Asset Dispositions,      Net	25	97	(21)	(27)	74		69	(9)			60
Other, Net	23	42	34	19	118		20	21			41
Total	3,983	7,407	7,593	6,719	25,702		6,044	5,573			11,617
Operating Expenses
Lease and Well	318	324	335	354	1,331		359	348			707
Transportation Costs	228	244	257	237	966		236	236			472
Gathering and Processing Costs	144	152	167	158	621		159	160			319
Exploration Costs	45	35	35	44	159		50	47			97
Dry Hole Costs	3	20	18	4	45		1	—			1
Impairments	55	91	94	142	382		34	35			69
Marketing Costs	1,283	2,127	1,621	1,504	6,535		1,361	1,456			2,817
Depreciation, Depletion and Amortization	847	911	906	878	3,542		798	866			1,664
General and Administrative	124	128	162	156	570		145	142			287
Taxes Other Than Income	390	472	334	389	1,585		329	313			642
Total	3,437	4,504	3,929	3,866	15,736		3,472	3,603			7,075
Operating Income	546	2,903	3,664	2,853	9,966		2,572	1,970			4,542
Other Income (Expense), Net	(1)	27	40	48	114		65	51			116
Income Before Interest Expense and      Income Taxes	545	2,930	3,704	2,901	10,080		2,637	2,021			4,658
Interest Expense, Net	48	48	41	42	179		42	35			77
Income Before Income Taxes	497	2,882	3,663	2,859	9,901		2,595	1,986			4,581
Income Tax Provision	107	644	809	582	2,142		572	433			1,005
Net Income	390	2,238	2,854	2,277	7,759		2,023	1,553			3,576
Dividends Declared per Common Share	1.7500	2.5500	2.2500	2.3250	8.8750		1.8250	0.8250			2.6500
Net Income Per Share
Basic	0.67	3.84	4.90	3.90	13.31		3.46	2.68			6.14
Diluted	0.67	3.81	4.86	3.87	13.22		3.45	2.66			6.10
Average Number of Common Shares
Basic	582	583	583	584	583		584	580			582
Diluted	586	588	587	588	587		587	584			586

 

Wellhead Volumes and Prices
(Unaudited)
	2022							2023
	1st Qtr		2nd Qtr	3rd Qtr	4th Qtr	Year		1st Qtr	2nd Qtr	3rd Qtr	4th Qtr	YTD
Crude Oil and Condensate Volumes (MBbld)(A)
United States	449.4		463.5	464.6	465.1	460.7		457.1	476.0			466.6
Trinidad	0.7		0.6	0.5	0.5	0.6		0.6	0.6			0.6
Total	450.1		464.1	465.1	465.6	461.3		457.7	476.6			467.2
Average Crude Oil and Condensate Prices ($/ Bbl) (B)
United States	$ 96.02		$ 111.26	$ 96.05	$ 85.68	$ 97.22		$ 77.27	$ 74.98			$ 76.10
Trinidad	83.82		98.29	84.98	75.21	86.16		68.98	64.88			66.92
Composite	96.00		111.25	96.04	85.67	97.21		77.26	74.97			76.09
Natural Gas Liquids Volumes (MBbld) (A)
United States	190.3		201.9	209.3	189.0	197.7		212.2	215.7			213.9
Total	190.3		201.9	209.3	189.0	197.7		212.2	215.7			213.9
Average Natural Gas Liquids Prices ($/Bbl) (B)
United States	$ 39.77		$ 42.28	$ 36.02	$ 28.55	$ 36.70		$ 25.67	$ 20.85			$ 23.23
Composite	39.77		42.28	36.02	28.55	36.70		25.67	20.85			23.23
Natural Gas Volumes (MMcfd) (A)
United States	1,249		1,324	1,306	1,378	1,315		1,475	1,513			1,494
Trinidad	209		204	163	149	180		164	155			160
Total	1,458		1,528	1,469	1,527	1,495		1,639	1,668			1,654
Average Natural Gas Prices ($/Mcf) (B)
United States	$     5.81		$       7.77	$       9.35	$       6.12	$       7.27		$       3.47	$       2.07			$     2.76
Trinidad (D)	3.36		3.42	7.45	3.97	4.43		3.87	3.45			3.67
Composite	5.46		7.19	9.14	5.91	6.93		3.51	2.20			2.84
Crude Oil Equivalent Volumes (MBoed) (C)
United States	847.8		886.1	891.6	883.8	877.5		915.0	943.8			929.5
Trinidad	35.5		34.6	27.6	25.3	30.7		28.0	26.5			27.2
Total	883.3		920.7	919.2	909.1	908.2		943.0	970.3			956.7
Total MMBoe (C)	79.5		83.8	84.6	83.6	331.5		84.9	88.3			173.2

(A)	Thousand barrels per day or million cubic feet per day, as applicable.
(B)	Dollars per barrel or per thousand cubic feet, as applicable. Excludes the impact of financial commodity derivative instruments (see Note 12 to the Condensed Consolidated Financial Statements in EOG's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2023).
(C)	Thousand barrels of oil equivalent per day or million barrels of oil equivalent, as applicable; includes crude oil and condensate, NGLs and natural gas. Crude oil equivalent volumes are determined using a ratio 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 MBoed amount by the number of days in the period and then dividing that amount by one thousand.
(D)	Includes positive revenue adjustment of $3.37 per Mcf and $0.76 per Mcf ($0.37 per Mcf and $0.09 per Mcf of EOG's composite wellhead natural gas price) for the three months ended September 30, 2022 and the twelve months ended December 31, 2022, respectively, related to a price adjustment per a provision of the natural gas sales contract with the National Gas Company of Trinidad and Tobago Limited and its subsidiary amended in July 2022 for natural gas sales during the period from September 2020 through June 2022.

 

Balance Sheets
In millions of USD (Unaudited)
	2022					2023
	MAR	JUN	SEP	DEC		MAR	JUN	SEP	DEC
Current Assets
Cash and Cash Equivalents	4,009	3,073	5,272	5,972		5,018	4,764
Accounts Receivable, Net	3,213	3,735	3,343	2,774		2,455	2,263
Inventories	586	739	872	1,058		1,131	1,355
Assets from Price Risk Management Activities	—	1	—	—		—	—
Income Taxes Receivable	—	—	93	97		—	1
Other	671	605	621	574		580	523
Total	8,479	8,153	10,201	10,475		9,184	8,906
Property, Plant and Equipment
Oil and Gas Properties (Successful Efforts Method)	65,408	66,098	67,065	67,322		67,907	69,178
Other Property, Plant and Equipment	4,801	4,862	4,659	4,786		5,101	5,282
Total Property, Plant and Equipment	70,209	70,960	71,724	72,108		73,008	74,460
Less: Accumulated Depreciation, Depletion and Amortization	(41,747)	(42,113)	(42,623)	(42,679)		(42,785)	(43,550)
Total Property, Plant and Equipment, Net	28,462	28,847	29,101	29,429		30,223	30,910
Deferred Income Taxes	13	12	18	33		31	33
Other Assets	1,143	1,127	1,167	1,434		1,587	1,638
Total Assets	38,097	38,139	40,487	41,371		41,025	41,487
Current Liabilities
Accounts Payable	2,660	2,896	2,718	2,532		2,438	2,205
Accrued Taxes Payable	1,130	594	542	405		637	425
Dividends Payable	436	437	437	482		482	478
Liabilities from Price Risk Management Activities	260	79	243	169		31	22
Current Portion of Long-Term Debt	1,283	1,282	1,282	1,283		33	34
Current Portion of Operating Lease Liabilities	223	216	235	296		354	335
Other	272	264	289	346		253	232
Total	6,264	5,768	5,746	5,513		4,228	3,731
Long-Term Debt	3,816	3,809	3,802	3,795		3,787	3,780
Other Liabilities	2,191	2,067	2,573	2,574		2,620	2,581
Deferred Income Taxes	4,286	4,183	4,517	4,710		4,943	5,138
Commitments and Contingencies
Stockholders' Equity
Common Stock, $0.01 Par	206	206	206	206		206	206
Additional Paid in Capital	6,095	6,128	6,155	6,187		6,219	6,257
Accumulated Other Comprehensive Loss	(13)	(12)	(6)	(8)		(8)	(9)
Retained Earnings	15,283	16,028	17,563	18,472		19,423	20,497
Common Stock Held in Treasury	(31)	(38)	(69)	(78)		(393)	(694)
Total Stockholders' Equity	21,540	22,312	23,849	24,779		25,447	26,257
Total Liabilities and Stockholders' Equity	38,097	38,139	40,487	41,371		41,025	41,487

 

Cash Flows Statements
In millions of USD (Unaudited)
		2022							2023
		1st Qtr	2nd Qtr		3rd Qtr	4th Qtr	Year		1st Qtr	2nd Qtr	3rd Qtr	4th Qtr	YTD
Cash Flows from Operating Activities
Reconciliation of Net Income to Net Cash      Provided by Operating Activities:
Net Income		390	2,238		2,854	2,277	7,759		2,023	1,553			3,576
Items Not Requiring (Providing) Cash
Depreciation, Depletion and Amortization		847	911		906	878	3,542		798	866			1,664
Impairments		55	91		94	142	382		34	35			69
Stock-Based Compensation Expenses		35	30		34	34	133		34	35			69
Deferred Income Taxes		(465)	(102)		327	179	(61)		234	194			428
(Gains) Losses on Asset Dispositions, Net		(25)	(97)		21	27	(74)		(69)	9			(60)
Other, Net		6	(16)		(5)	15	—		4	2			6
Dry Hole Costs		3	20		18	4	45		1	—			1
Mark-to-Market Financial Commodity Derivative      Contracts (Gains) Losses, Net		2,820	1,377		18	(233)	3,982		(376)	(101)			(477)
Net Cash Payments for Settlements of      Financial Commodity Derivative      Contracts		(296)	(2,114)		(847)	(244)	(3,501)		(123)	(30)			(153)
Other, Net		2	19		12	12	45		(1)	—			(1)
Changes in Components of Working Capital and      Other Assets and Liabilities
Accounts Receivable		(878)	(522)		392	661	(347)		338	137			475
Inventories		(14)	(157)		(140)	(223)	(534)		(77)	(226)			(303)
Accounts Payable		130	259		(88)	(211)	90		(77)	(231)			(308)
Accrued Taxes Payable		613	(536)		(53)	(137)	(113)		232	(212)			20
Other Assets		(213)	71		(129)	(93)	(364)		52	43			95
Other Liabilities		(2,250)	433		1,269	282	(266)		193	(47)			146
Changes in Components of Working Capital      Associated with Investing Activities		68	143		90	74	375		35	250			285
Net Cash Provided by Operating Activities		828	2,048		4,773	3,444	11,093		3,255	2,277			5,532
Investing Cash Flows
Additions to Oil and Gas Properties		(939)	(1,349)		(1,102)	(1,229)	(4,619)		(1,305)	(1,341)			(2,646)
Additions to Other Property, Plant and Equipment		(70)	(75)		(103)	(133)	(381)		(319)	(180)			(499)
Proceeds from Sales of Assets		121	110		79	39	349		92	29			121
Other Investing Activities		—	(30)		—	—	(30)		—	—			—
Changes in Components of Working Capital      Associated with Investing Activities		(68)	(143)		(90)	(74)	(375)		(35)	(250)			(285)
Net Cash Used in Investing Activities		(956)	(1,487)		(1,216)	(1,397)	(5,056)		(1,567)	(1,742)			(3,309)
Financing Cash Flows
Long-Term Debt Repayments		—	—		—	—	—		(1,250)	—			(1,250)
Dividends Paid		(1,023)	(1,486)		(1,312)	(1,327)	(5,148)		(1,067)	(480)			(1,547)
Treasury Stock Purchased		(43)	(15)		(37)	(23)	(118)		(317)	(302)			(619)
Proceeds from Stock Options Exercised and      Employee Stock Purchase Plan		4	13		—	11	28		—	9			9
Debt Issuance Costs		—	—		—	—	—		—	(8)			(8)
Repayment of Finance Lease Liabilities		(10)	(9)		(8)	(8)	(35)		(8)	(8)			(16)
Net Cash Used in Financing Activities		(1,072)	(1,497)		(1,357)	(1,347)	(5,273)		(2,642)	(789)			(3,431)
Effect of Exchange Rate Changes on Cash		—	—		(1)	—	(1)		—	—			—
Increase (Decrease) in Cash and Cash Equivalents		(1,200)	(936)		2,199	700	763		(954)	(254)			(1,208)
Cash and Cash Equivalents at Beginning of Period		5,209	4,009		3,073	5,272	5,209		5,972	5,018			5,972
Cash and Cash Equivalents at End of Period		4,009	3,073		5,272	5,972	5,972		5,018	4,764			4,764

 

Non-GAAP Financial Measure
To supplement the presentation of its financial results prepared in accordance with generally accepted accounting principles in the United States of America (GAAP), EOG's quarterly earnings releases and related conference calls, accompanying investor presentation slides and presentation slides for investor conferences contain certain financial measures that are not prepared or presented in accordance with GAAP. These non-GAAP financial measures may include, but are not limited to, Adjusted Net Income (Loss), Cash Flow from Operations Before Working Capital, Free Cash Flow, Net Debt and related statistics.
A reconciliation of each of these measures to their most directly comparable GAAP financial measure and related discussion is included in the tables on the following pages and can also be found in the "Reconciliations & Guidance" section of the "Investors" page of the EOG website at www.eogresources.com.
As further discussed in the tables on the following pages, EOG believes these measures may be useful to investors who follow the practice of some industry analysts who make certain adjustments to GAAP measures (for example, to exclude non- recurring items) to facilitate comparisons to others in EOG's industry, and who utilize non-GAAP measures in their calculations of certain statistics (for example, return on capital employed and return on equity) used to evaluate EOG's performance.
EOG believes that the non-GAAP measures presented, when viewed in combination with its financial results prepared in accordance with GAAP, provide a more complete understanding of the factors and trends affecting the company's performance. As is discussed in the tables on the following pages, EOG uses these non-GAAP measures for purposes of (i) comparing EOG's financial performance with the financial performance of other companies in the industry and (ii) analyzing EOG's financial performance across periods.
The non-GAAP measures presented should not be considered in isolation, and should not be considered as a substitute for, or as an alternative to, EOG's reported Net Income (Loss), Long-Term Debt (including Current Portion of Long-Term Debt), Net Cash Provided by Operating Activities and other financial results calculated in accordance with GAAP. The non-GAAP measures presented should be read in conjunction with EOG's consolidated financial statements prepared in accordance with GAAP.
In addition, because not all companies use identical calculations, EOG's presentation of non-GAAP measures may not be comparable to, and may be calculated differently from, similarly titled measures disclosed by other companies, including its peer companies. EOG may also change the calculation of one or more of its non-GAAP measures from time to time – for example, to account for changes in its business and operations or to more closely conform to peer company or industry analysts' practices.
Direct ATROR
The calculation of EOG's direct after-tax rate of return (ATROR) is based on EOG's net estimated recoverable reserves for a particular well(s) or play, the estimated net present value of the future net cash flows from such reserves (for which EOG utilizes certain assumptions regarding future commodity prices and operating costs) and EOG's direct net costs incurred in drilling or acquiring such well(s). As such, EOG's direct ATROR for a particular well(s) or play cannot be calculated from EOG's consolidated financial statements.
Adjusted Net Income (Loss)
In millions of USD, except share data (in millions) and per share data (Unaudited)
The following tables adjust reported Net Income (Loss) (GAAP) to reflect actual net cash received from (payments for) settlements of financial commodity derivative contracts by eliminating the unrealized mark-to-market (gains) losses from these transactions, to eliminate the net (gains) losses on asset dispositions, to add back impairment charges related to certain of EOG's assets (which are generally (i) attributable to declines in commodity prices, (ii) related to sales of certain oil and gas properties or (iii) the result of certain other events or decisions (e.g., a periodic review of EOG's oil and gas properties or other assets)), and to make certain other adjustments to exclude non-recurring and certain other items as further described below. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported company earnings to match hedge realizations to production settlement months and make certain other adjustments to exclude non-recurring and certain other items. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry.

	2Q 2023
	Before Tax	Income Tax Impact	After Tax	Diluted Earnings per Share
Reported Net Income (GAAP)	1,986	(433)	1,553	2.66
Adjustments:
Gains on Mark-to-Market Financial Commodity Derivative Contracts,          Net	(101)	22	(79)	(0.14)
Net Cash Payments for Settlements of Financial Commodity      Derivative Contracts (1)	(30)	6	(24)	(0.04)
Add: Losses on Asset Dispositions, Net	9	(2)	7	0.01
Adjustments to Net Income	(122)	26	(96)	(0.17)
Adjusted Net Income (Non-GAAP)	1,864	(407)	1,457	2.49
Average Number of Common Shares (Non-GAAP)
Basic				580
Diluted				584

(1)	Consistent with its customary practice, in calculating Adjusted Net Income (Loss) (non-GAAP), EOG subtracts from reported Net Income (Loss) (GAAP) the total net cash paid for settlements of financial commodity derivative contracts during such period. For the three months ended June 30, 2023, such amount was $30 million.

 

Adjusted Net Income (Loss)
(Continued)
In millions of USD, except share data (in millions) and per share data (Unaudited)
	1Q 2023
	Before Tax	Income Tax Impact	After Tax	Diluted Earnings per Share
Reported Net Income (GAAP)	2,595	(572)	2,023	3.45
Adjustments:
Gains on Mark-to-Market Financial Commodity Derivative Contracts,      Net	(376)	81	(295)	(0.51)
Net Cash Payments for Settlements of Financial Commodity           Derivative Contracts (1)	(123)	27	(96)	(0.16)
Less: Gains on Asset Dispositions, Net	(69)	15	(54)	(0.09)
Adjustments to Net Income	(568)	123	(445)	(0.76)
Adjusted Net Income (Non-GAAP)	2,027	(449)	1,578	2.69
Average Number of Common Shares (Non-GAAP)
Basic				584
Diluted				587

(1)	Consistent with its customary practice, in calculating Adjusted Net Income (Loss) (non-GAAP), EOG subtracts from reported Net Income (Loss) (GAAP) the total net cash paid for settlements of financial commodity derivative contracts during such period. For the three months ended March 31, 2023, such amount was $123 million.

 

Adjusted Net Income (Loss) (Continued)
In millions of USD, except share data (in millions) and per share data (Unaudited)
	4Q 2022
	Before Tax	Income Tax Impact	After Tax	Diluted Earnings per Share
Reported Net Income (GAAP)	2,859	(582)	2,277	3.87
Adjustments:
Gains on Mark-to-Market Financial Commodity Derivative Contracts,      Net	(233)	57	(176)	(0.31)
Net Cash Payments for Settlements of Financial Commodity      Derivative Contracts (1)	(244)	48	(196)	(0.33)
Add: Losses on Asset Dispositions, Net	27	(6)	21	0.04
Add: Certain Impairments	31	(16)	15	0.03
Adjustments to Net Income	(419)	83	(336)	(0.57)
Adjusted Net Income (Non-GAAP)	2,440	(499)	1,941	3.30
Average Number of Common Shares (Non-GAAP)
Basic				584
Diluted				588

(1)	Consistent with its customary practice, in calculating Adjusted Net Income (Loss) (non-GAAP), EOG subtracts from reported Net Income (Loss) (GAAP) the total net cash paid for settlements of financial commodity derivative contracts during such period. For the three months ended December 31, 2022, such amount was $244 million.

 

Adjusted Net Income (Loss)
(Continued)
In millions of USD, except share data (in millions) and per share data (Unaudited)
	3Q 2022
	Before Tax	Income Tax Impact	After Tax	Diluted Earnings per Share
Reported Net Income (GAAP)	3,663	(809)	2,854	4.86
Adjustments:
Losses on Mark-to-Market Financial Commodity Derivative Contracts,            Net	18	(4)	14	0.03
Net Cash Payments for Settlements of Financial Commodity      Derivative Contracts (1)	(847)	184	(663)	(1.13)
Add: Losses on Asset Dispositions, Net	21	(3)	18	0.03
Add: Certain Impairments	46	(8)	38	0.06
Less: Severance Tax Refund	(115)	25	(90)	(0.15)
Add: Severance Tax Consulting Fees	16	(3)	13	0.02
Less: Interest on Severance Tax Refund	(7)	2	(5)	(0.01)
Adjustments to Net Income	(868)	193	(675)	(1.15)
Adjusted Net Income (Non-GAAP)	2,795	(616)	2,179	3.71
Average Number of Common Shares (Non-GAAP)
Basic				583
Diluted				587

(1)

Consistent with its customary practice, in calculating Adjusted Net Income (Loss) (non-GAAP), EOG subtracts from reported Net Income (Loss) (GAAP) the total net cash paid for settlements of financial commodity derivative contracts during such period. For the three months ended September 30, 2022, such amount was $847 million, of which $63 million was related to the early termination of certain contracts.

 

Adjusted Net Income (Loss)
(Continued)
In millions of USD, except share data (in millions) and per share data (Unaudited)
	2Q 2022
	Before Tax	Income Tax Impact	After Tax	Diluted Earnings per Share
Reported Net Income (GAAP)	2,882	(644)	2,238	3.81
Adjustments:
Losses on Mark-to-Market Financial Commodity Derivative Contracts, Net	1,377	(299)	1,078	1.82
Net Cash Payments for Settlements of Financial Commodity Derivative Contracts (1)	(2,114)	459	(1,655)	(2.81)
Less: Gains on Asset Dispositions, Net	(97)	21	(76)	(0.13)
Add: Certain Impairments	36	(7)	29	0.05
Adjustments to Net Income	(798)	174	(624)	(1.07)
Adjusted Net Income (Non-GAAP)	2,084	(470)	1,614	2.74
Average Number of Common Shares (Non-GAAP)
Basic				583
Diluted				588

(1)

Consistent with its customary practice, in calculating Adjusted Net Income (Loss) (non-GAAP), EOG subtracts from reported Net Income (Loss) (GAAP) the total net cash paid for settlements of financial commodity derivative contracts during such period. For the three months ended June 30, 2022, such amount was $2,114 million, of which $1,328 million was related to the early termination of certain contracts.

 

Net Income per Share
In millions of USD, except share data (in millions), per share data, production volume data and per Boe data (Unaudited)
1Q 2023 Net Income per Share (GAAP)		3.45
Realized Price
2Q 2023 Composite Average Wellhead Revenue per Boe	45.24
Less: 1Q 2023 Composite Average Wellhead Revenue per Boe	(49.37)
Subtotal	(4.13)
Multiplied by: 2Q 2023 Crude Oil Equivalent Volumes (MMBoe)	88.3
Total Change in Revenue	(365)
Less: Income Tax Benefit (Provision) Imputed (based on 22%)	80
Change in Net Income	(285)
Change in Diluted Earnings per Share		(0.49)
Wellhead Volumes
2Q 2023 Crude Oil Equivalent Volumes (MMBoe)	88.3
Less: 1Q 2023 Crude Oil Equivalent Volumes (MMBoe)	(84.9)
Subtotal	3.4
Multiplied by: 2Q 2023 Composite Average Margin per Boe (Non-GAAP)      (Including Total Exploration Costs)(refer to "Revenues Costs and Margins Per Barrel of Oil      Equivalent" schedule)	20.53
Change in Margin	70
Less: Income Tax Benefit (Provision) Imputed (based on 22%)	(15)
Change in Net Income	55
Change in Diluted Earnings per Share		0.09
Certain Operating Costs per Boe
1Q 2023 Total Cash Operating Costs (GAAP) and Total DD&A per Boe (refer to "Revenues,           Costs and Margins Per Barrel of Oil Equivalent" schedule)	19.99
Less: 2Q 2023 Total Cash Operating Costs (GAAP) and Total DD&A per Boe (refer to "Revenues,           Costs and Margins Per Barrel of Oil Equivalent" schedule)	(19.84)
Subtotal	0.15
Multiplied by: 2Q 2023 Crude Oil Equivalent Volumes (MMBoe)	88.3
Change in Before-Tax Net Income	13
Less: Income Tax Benefit (Provision) Imputed (based on 22%)	(3)
Change in Net Income	10
Change in Diluted Earnings per Share		0.02

 

Net Income Per Share
(Continued)
In millions of USD, except share data (in millions), per share data, production volume data and per Boe data (Unaudited)
Gains (Losses) on Mark-to-Market Financial Commodity Derivative Contracts, Net
2Q 2023 Net Gains (Losses) on Mark-to-Market Financial Commodity Derivative Contracts	101
Less: Income Tax Benefit (Provision)	(22)
After Tax - (a)	79
Less: 1Q 2023 Net Gains (Losses) on Mark-to-Market Financial Commodity Derivative Contracts	376
Less: Income Tax Benefit (Provision)	(81)
After Tax - (b)	295
Change in Net Income - (a) - (b)	(216)
Change in Diluted Earnings per Share		(0.37)
Other (1)		(0.04)
2Q 2023 Net Income per Share (GAAP)		2.66
2Q 2023 Average Number of Common Shares (GAAP) - Diluted	584

(1)	Includes gathering, processing and marketing revenue, gains (losses) on asset dispositions, other revenue, exploration, dry hole, impairments and marketing costs, taxes other than income, other income (expense), interest expense and the impact of changes in the effective income tax rate.

 

Adjusted Net Income Per Share
In millions of USD, except share data (in millions), per share data, production volume data and per Boe data (Unaudited)
1Q 2023 Adjusted Net Income per Share (Non-GAAP)		2.69
Realized Price
2Q 2023 Composite Average Wellhead Revenue per Boe	45.24
Less: 1Q 2023 Composite Average Wellhead Revenue per Boe	(49.37)
Subtotal	(4.13)
Multiplied by: 2Q 2023 Crude Oil Equivalent Volumes (MMBoe)	88.3
Total Change in Revenue	(365)
Less: Income Tax Benefit (Provision) Imputed (based on 22%)	80
Change in Net Income	(285)
Change in Diluted Earnings per Share		(0.49)
Wellhead Volumes
2Q 2023 Crude Oil Equivalent Volumes (MMBoe)	88.3
Less: 1Q 2023 Crude Oil Equivalent Volumes (MMBoe)	(84.9)
Subtotal	3.4
Multiplied by: 2Q 2023 Composite Average Margin per Boe (Non-GAAP) (Including Total      Exploration Costs) (refer to "Revenues, Costs and Margins Per Barrel of Oil Equivalent"      schedule)	20.53
Change in Margin	70
Less: Income Tax Benefit (Provision) Imputed (based on 22%)	(15)
Change in Net Income	55
Change in Diluted Earnings per Share		0.09
Certain Operating Costs per Boe
1Q 2023 Total Cash Operating Costs (Non-GAAP) and Total DD&A per Boe            (refer to "Revenues, Costs and Margins Per Barrel of Oil Equivalent" schedule)	19.99
Less: 2Q 2023 Total Cash Operating Costs (Non-GAAP) and Total DD&A per Boe            (refer to "Revenues, Costs and Margins Per Barrel of Oil Equivalent" schedule)	(19.84)
Subtotal	0.15
Multiplied by: 2Q 2023 Crude Oil Equivalent Volumes (MMBoe)	88.3
Change in Before-Tax Net Income	13
Less: Income Tax Benefit (Provision) Imputed (based on 22%)	(3)
Change in Net Income	10
Change in Diluted Earnings per Share		0.02

 

Adjusted Net Income Per Share
(Continued)
In millions of USD, except share data (in millions), per share data, production volume data and per Boe data (Unaudited)
Net Cash Received from (Payments for) Settlements of Financial Commodity Derivative Contracts
2Q 2023 Net Cash Received from (Payments for) Settlement of Financial Commodity Derivative      Contracts	(30)
Less: Income Tax Benefit (Provision)	6
After Tax - (a)	(24)
1Q 2023 Net Cash Received from (Payments for) Settlement of Financial Commodity Derivative      Contracts	(123)
Less: Income Tax Benefit (Provision)	27
After Tax - (b)	(96)
Change in Net Income - (a) - (b)	72
Change in Diluted Earnings per Share		0.12
Other (1)		0.06
2Q 2023 Adjusted Net Income per Share (Non-GAAP)		2.49
2Q 2023 Average Number of Common Shares (Non-GAAP) - Diluted	584

(1)	Includes gathering, processing and marketing revenue, other revenue, exploration, dry hole, impairments and marketing costs, taxes other than income, other income (expense), interest expense and the impact of changes in the effective income tax rate.

 

Cash Flow from Operations and Free Cash Flow
In millions of USD (Unaudited)
The following tables reconcile Net Cash Provided by Operating Activities (GAAP) to Cash Flow from Operations Before Working Capital (Non-GAAP). EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust Net Cash Provided by Operating Activities for Changes in Components of Working Capital and Other Assets and Liabilities, Changes in Components of Working Capital Associated with Investing and Financing Activities and certain other adjustments to exclude non-recurring and certain other items as further described below. EOG defines Free Cash Flow (Non-GAAP) for a given period as Cash Flow from Operations Before Working Capital (Non-GAAP) (see below reconciliation) for such period less the total capital expenditures (Non-GAAP) during such period, as is illustrated below. EOG management uses this information for comparative purposes within the industry.
	2022						2023
	1st Qtr	2nd Qtr	3rd Qtr	4th Qtr	Year		1st Qtr	2nd Qtr	3rd Qtr	4th Qtr	YTD
Net Cash Provided by Operating Activities (GAAP)	828	2,048	4,773	3,444	11,093		3,255	2,277			5,532
Adjustments:
Changes in Components of Working Capital and Other Assets and Liabilities
Accounts Receivable	878	522	(392)	(661)	347		(338)	(137)			(475)
Inventories	14	157	140	223	534		77	226			303
Accounts Payable	(130)	(259)	88	211	(90)		77	231			308
Accrued Taxes Payable	(613)	536	53	137	113		(232)	212			(20)
Other Assets	213	(71)	129	93	364		(52)	(43)			(95)
Other Liabilities	2,250	(433)	(1,269)	(282)	266		(193)	47			(146)
Changes in Components of Working Capital Associated with Investing Activities	(68)	(143)	(90)	(74)	(375)		(35)	(250)			(285)
Cash Flow from Operations Before Working Capital (Non-GAAP)	3,372	2,357	3,432	3,091	12,252		2,559	2,563			5,122
Cash Flow from Operations Before Working Capital (Non-GAAP)	3,372	2,357	3,432	3,091	12,252		2,559	2,563			5,122
Less:
Total Capital Expenditures (Non-GAAP) (a)	(1,009)	(1,071)	(1,166)	(1,361)	(4,607)		(1,489)	(1,521)			(3,010)
Free Cash Flow (Non-GAAP)	2,363	1,286	2,266	1,730	7,645		1,070	1,042			2,112
(a) See below reconciliation of Total Expenditures (GAAP) to Total Capital Expenditures (Non-GAAP):
	2022						2023
	1st Qtr	2nd Qtr	3rd Qtr	4th Qtr	Year		1st Qtr	2nd Qtr	3rd Qtr	4th Qtr	YTD
Total Expenditures (GAAP)	1,144	1,521	1,410	1,535	5,610		1,717	1,664			3,381
Less:
Asset Retirement Costs	(27)	(43)	(139)	(89)	(298)		(10)	(26)			(36)
Non-Cash Acquisition Costs of Unproved Properties	(58)	(21)	(28)	(20)	(127)		(31)	(28)			(59)
Non-Cash Development Drilling	—	—	—	—	—		—	(35)			(35)
Acquisition Costs of Proved Properties	(5)	(351)	(42)	(21)	(419)		(4)	(6)			(10)
Acquisition Costs of Other Property, Plant and Equipment	—	—	—	—	—		(133)	(1)			(134)
Exploration Costs	(45)	(35)	(35)	(44)	(159)		(50)	(47)			(97)
Total Capital Expenditures (Non-GAAP)	1,009	1,071	1,166	1,361	4,607		1,489	1,521			3,010

 

Net Debt-to-Total Capitalization Ratio
In millions of USD, except ratio data (Unaudited)
The following tables reconcile Current and Long-Term Debt (GAAP) to Net Debt (Non-GAAP) and Total Capitalization (GAAP) to Total Capitalization (Non-GAAP), as used in the Net Debt-to-Total Capitalization ratio calculation. A portion of the cash  is associated with international subsidiaries; tax considerations may impact debt paydown. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize Net Debt and Total Capitalization (Non-GAAP) in their Net Debt-to-Total Capitalization ratio calculation. EOG management uses this information for comparative purposes within the industry.
	June 30, 2023	March 31, 2023	December 31, 2022	September 30, 2022	June 30, 2022
Total Stockholders' Equity - (a)	26,257	25,447	24,779	23,849	22,312
Current and Long-Term Debt (GAAP) - (b)	3,814	3,820	5,078	5,084	5,091
Less: Cash	(4,764)	(5,018)	(5,972)	(5,272)	(3,073)
Net Debt (Non-GAAP) - (c)	(950)	(1,198)	(894)	(188)	2,018
Total Capitalization (GAAP) - (a) + (b)	30,071	29,267	29,857	28,933	27,403
Total Capitalization (Non-GAAP) - (a) + (c)	25,307	24,249	23,885	23,661	24,330
Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)]	12.7 %	13.1 %	17.0 %	17.6 %	18.6 %
Net Debt-to-Total Capitalization (Non-GAAP) - (c) /      [(a) + (c)]	-3.8 %	-4.9 %	-3.7 %	-0.8 %	8.3 %

 

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SOURCE EOG Resources, Inc.