Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis addresses material changes in our results of operations for the three-month and six-month periods ended June 30, 2024 compared to previous periods, and in our financial condition and liquidity since December 31, 2023. For information regarding our critical accounting policies and estimates, see our 2023 Annual Report on Form 10-K under “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Executive Over****view

We are a leading independent oil and natural gas exploration and production company whose operations are focused onshore in the United States. Our operations are currently focused in five core areas: the Delaware Basin, Eagle Ford, Anadarko Basin, Williston Basin and Powder River Basin. Our asset base is underpinned by premium acreage in the economic core of the Delaware Basin and our diverse, top-tier resource plays, providing a deep inventory of opportunities for years to come.

In July 2024, Devon announced it had entered into an agreement to acquire the Williston Basin business of Grayson Mill Energy. The purchase price for the transaction consists of $3.25 billion of cash and approximately 37 million shares of Devon common stock, in each case subject to various purchase price adjustments. The transaction is expected to close by the end of the third quarter of 2024 and increase our volumes in 2025 by approximately 100 MBoe/d, with approximately 55% being oil. The acquisition will allow us to efficiently expand our oil production and operating scale, creating immediate and long-term, sustainable value to shareholders over time. As evidenced by this recent acquisition, we remain focused on building economic value by executing on our strategic priorities of moderating production growth, emphasizing capital and operational efficiencies, optimizing reinvestment rates to maximize free cash flow, maintaining low leverage, delivering cash returns to our shareholders and pursuing ESG excellence. Our recent performance highlights for these priorities include the following items for the second quarter of 2024:

Oil production totaled 335 MBbls/d, exceeding our plan by 3%.

Expanded share repurchase program to $5.0 billion and have repurchased approximately 54.7 million of our common shares for approximately $2.7 billion, or $50.28 per share since inception of the plan.

Exited with $4.2 billion of liquidity, including $1.2 billion of cash.

Generated $1.5 billion of operating cash flow and $6.7 billion for the past twelve trailing months.

Including variable dividends, paid dividends of $223 million and have declared approximately $276 million of dividends to be paid in the third quarter of 2024.

Earnings attributable to Devon were $844 million, or $1.34 per diluted share.

Core earnings (Non-GAAP) were $885 million, or $1.41 per diluted share.

We remain committed to capital discipline and delivering the objectives that underpin our current plan. Those objectives prioritize value creation through moderated capital investment and production growth, particularly with a view of the volatility in commodity prices, supply chain constraints and the economic uncertainty arising from inflation and geopolitical events. Our cash-return objectives remain focused on opportunistic share repurchases, funding our fixed and variable dividends, repaying debt at upcoming maturities and building cash balances.

Res****ults of Operations

The following graphs, discussion and analysis are intended to provide an understanding of our results of operations and current financial condition. To facilitate the review, these numbers are being presented before consideration of noncontrolling interests.

Q2 2024 vs. Q1 2024

Our second quarter 2024 and first quarter 2024 net earnings were $855 million and $609 million, respectively. The graph below shows the change in net earnings from the first quarter of 2024 to the second quarter of 2024. The material changes are further discussed by category on the following pages.

Production Volumes


	Q2 2024		% of Total			Q1 2024		Change
Oil (MBbls/d)
Delaware Basin		221		66	%		208		6	%
Eagle Ford		46		14	%		43		8	%
Anadarko Basin		14		4	%		11		27	%
Williston Basin		37		11	%		40		-6	%
Powder River Basin		13		4	%		13		-1	%
Other		4		1	%		4		-3	%
Total		335		100	%		319		5	%


	Q2 2024		% of Total			Q1 2024		Change
Gas (MMcf/d)
Delaware Basin		712		63	%		695		2	%
Eagle Ford		92		8	%		79		16	%
Anadarko Basin		244		21	%		223		9	%
Williston Basin		71		6	%		63		13	%
Powder River Basin		18		2	%		18		0	%
Other		—		0	%		1	N/M
Total		1,137		100	%		1,079		5	%


	Q2 2024		% of Total			Q1 2024		Change
NGLs (MBbls/d)
Delaware Basin		121		66	%		113		7	%
Eagle Ford		17		10	%		14		26	%
Anadarko Basin		30		16	%		26		15	%
Williston Basin		12		7	%		10		19	%
Powder River Basin		2		1	%		2		3	%
Other		—		0	%		—	N/M
Total		182		100	%		165		11	%


	Q2 2024		% of Total			Q1 2024		Change
Combined (MBoe/d)
Delaware Basin		461		65	%		437		5	%
Eagle Ford		79		11	%		70		13	%
Anadarko Basin		84		12	%		74		14	%
Williston Basin		61		9	%		61		1	%
Powder River Basin		18		2	%		18		0	%
Other		4		1	%		4		0	%
Total		707		100	%		664		7	%

From the first quarter of 2024 to the second quarter of 2024, the change in volumes contributed to a $151 million increase in earnings. The increase in volumes was primarily due to new well activity in the Delaware Basin, Anadarko Basin and Eagle Ford.

Realized Prices


	Q2 2024			Realization	Q1 2024			Change
Oil (per Bbl)
WTI index	$	80.62			$	77.01			5	%
Realized price, unhedged	$	79.10		98%	$	75.40			5	%
Cash settlements	$	(0.15	)		$	(0.25	)
Realized price, with hedges	$	78.95		98%	$	75.15			5	%


	Q2 2024		Realization	Q1 2024		Change
Gas (per Mcf)
Henry Hub index	$	1.89		$	2.25		-16	%
Realized price, unhedged	$	0.55	29%	$	1.30		-58	%
Cash settlements	$	0.55		$	0.32
Realized price, with hedges	$	1.10	58%	$	1.62		-32	%


	Q2 2024		Realization	Q1 2024			Change
NGLs (per Bbl)
WTI index	$	80.62		$	77.01			5	%
Realized price, unhedged	$	19.60	24%	$	20.81			-6	%
Cash settlements	$	0.11		$	(0.08	)
Realized price, with hedges	$	19.71	24%	$	20.73			-5	%


	Q2 2024		Q1 2024		Change
Combined (per Boe)
Realized price, unhedged	$	43.44	$	43.52		0	%
Cash settlements	$	0.85	$	0.39
Realized price, with hedges	$	44.29	$	43.91		1	%

From the first quarter of 2024 to the second quarter of 2024, realized prices contributed to a $16 million increase in earnings. Unhedged oil prices increased primarily due to higher WTI index prices, while unhedged gas and NGL prices decreased primarily due to lower Henry Hub and Mont Belvieu index prices. The decrease in the Henry Hub index price was partially offset by hedge cash settlements primarily related to gas commodities.

We currently have approximately 30% and 25% of our remaining anticipated 2024 oil and gas production hedged, respectively.

Hedge Settlements


	Q2 2024			Q1 2024			Change
	Q
Oil	$	(5	)	$	(7	)		29	%
Natural gas		57			32			78	%
NGL		2			(1	)	N/M
Total cash settlements (1)	$	54		$	24			125	%

(1)

Included as a component of oil, gas and NGL derivatives on the consolidated statements of comprehensive earnings.

Cash settlements as presented in the tables above represent realized gains or losses related to the instruments described in Note 3 in “Part I. Financial Information – Item 1. Financial Statements” in this report.

Production Expenses


	Q2 2024			Q1 2024			Change
LOE	$	383		$	380			1	%
Gathering, processing & transportation		197			180			9	%
Production taxes		188			175			7	%
Property taxes		20			16			25	%
Total	$	788		$	751			5	%
Per Boe:
LOE	$	5.95		$	6.29			-5	%
Gathering, processing & transportation	$	3.07		$	2.98			3	%
Percent of oil, gas and NGL sales:
Production taxes		6.7	%		6.7	%		1	%

Production expenses increased during the second quarter of 2024 primarily due to increased activity as well as higher production taxes resulting from an increase in oil prices.

Field-Level Cash Margin

The table below presents the field-level cash margin for each of our operating areas. Field-level cash margin is computed as oil, gas and NGL sales less production expenses and is not a measure defined by GAAP. A reconciliation to the comparable GAAP measures is found in “Non-GAAP Measures” in this Item 2. The changes in production volumes, realized prices and production expenses, shown above, had the following impact on our field-level cash margins by asset.


	Q2 2024		$ per BOE		Q1 2024		$ per BOE
Field-level cash margin (Non-GAAP)
Delaware Basin	$	1,346	$	32.12	$	1,275	$	32.06
Eagle Ford		303	$	42.15		266	$	41.82
Anadarko Basin		119	$	15.48		98	$	14.64
Williston Basin		160	$	28.62		164	$	29.74
Powder River Basin		65	$	39.44		60	$	36.00
Other		15	N/M			15	N/M
Total	$	2,008	$	31.19	$	1,878	$	31.09

DD&A


	Q2 2024		Q1 2024		Change
Oil and gas per Boe	$	11.56	$	11.57		0	%

Oil and gas	$	744	$	699		6	%
Other property and equipment		24		23		2	%
Total	$	768	$	722		6	%

DD&A increased in the second quarter of 2024 primarily due to higher volumes.

G&A


	Q2 2024		Q1 2024		Change
G&A per Boe	$	1.77	$	1.89		-7	%

Labor and benefits	$	62	$	63		-2	%
Non-labor		52		51		2	%
Total	$	114	$	114		0	%

Other Items


	Q2 2024			Q1 2024			Change in earnings
Commodity hedge valuation changes (1)	$	(31	)	$	(169	)	$	138
Marketing and midstream operations		(10	)		(21	)		11
Exploration expenses		3			9			6
Asset dispositions		15			1			(14	)
Net financing costs		76			76			—
Other, net		5			22			17
							$	158

(1)

Included as a component of oil, gas and NGL derivatives on the consolidated statements of comprehensive earnings.

We recognize fair value changes on our oil, gas and NGL derivative instruments in each reporting period. The changes in fair value resulted from new positions and settlements that occurred during each period, as well as the relationship between contract prices and the associated forward curves. For additional information, see Note 3 in “Part I. Financial Information – Item 1. Financial Statements” in this report.

Income Taxes


	Q2 2024			Q1 2024
Current expense	$	146		$	119
Deferred expense		39			40
Total expense	$	185		$	159
Current tax rate		14	%		16	%
Deferred tax rate		4	%		5	%
Effective income tax rate		18	%		21	%

For discussion on income taxes, see Note 5 in “Part I. Financial Information – Item 1. Financial Statements” in this report.

June 30, 2024 YTD vs. June 30, 2023 YTD

Our six months ended June 30, 2024 net earnings were $1.5 billion, compared to net earnings of $1.7 billion for the first six months ended June 30, 2023. The graph below shows the change in net earnings from the six months ended June 30, 2023 to the six months ended June 30, 2024. The material changes are further discussed by category on the following pages.

Production Volumes


	Six Months Ended June 30,
	2024		% of Total			2023		Change
Oil (MBbls/d)
Delaware Basin		215		66	%		210		2	%
Eagle Ford		45		13	%		43		5	%
Anadarko Basin		12		4	%		15		-19	%
Williston Basin		39		12	%		36		8	%
Powder River Basin		13		4	%		14		-7	%
Other		3		1	%		4	N/M
Total		327		100	%		322		2	%


	Six Months Ended June 30,
	2024		% of Total			2023		Change
Gas (MMcf/d)
Delaware Basin		703		63	%		638		10	%
Eagle Ford		86		8	%		84		2	%
Anadarko Basin		233		21	%		245		-5	%
Williston Basin		67		6	%		57		18	%
Powder River Basin		18		2	%		17		6	%
Other		1		0	%		1	N/M
Total		1,108		100	%		1,042		6	%


	Six Months Ended June 30,
	2024		% of Total			2023		Change
NGLs (MBbls/d)
Delaware Basin		117		67	%		101		15	%
Eagle Ford		16		9	%		15		4	%
Anadarko Basin		28		16	%		29		-3	%
Williston Basin		11		7	%		9		26	%
Powder River Basin		2		1	%		2		1	%
Other		—		0	%		—	N/M
Total		174		100	%		156		11	%


	Six Months Ended June 30,
	2024		% of Total			2023		Change
Combined (MBoe/d)
Delaware Basin		449		65	%		418		7	%
Eagle Ford		75		10	%		71		4	%
Anadarko Basin		79		12	%		85		-7	%
Williston Basin		61		9	%		54		12	%
Powder River Basin		18		3	%		19		-4	%
Other		4		1	%		5		-8	%
Total		686		100	%		652		5	%

From the six months ended June 30, 2023 to the six months ended June 30, 2024, the change in volumes contributed to a $190 million increase in earnings. Volumes increased primarily due to new well activity in the Delaware Basin, Williston Basin and Eagle Ford, which was partially offset by natural well declines in the Anadarko Basin.

Realized Prices


	Six Months Ended June 30,
	2024			Realization	2023			Change
Oil (per Bbl)
WTI index	$	78.82			$	74.96			5	%
Realized price, unhedged	$	77.30		98%	$	73.02			6	%
Cash settlements	$	(0.20	)		$	(0.06	)
Realized price, with hedges	$	77.10		98%	$	72.96			6	%


	Six Months Ended June 30,
	2024		Realization	2023		Change
Gas (per Mcf)
Henry Hub index	$	2.07		$	2.77		-25	%
Realized price, unhedged	$	0.92	44%	$	1.77		-48	%
Cash settlements	$	0.44		$	0.29
Realized price, with hedges	$	1.36	66%	$	2.06		-34	%


	Six Months Ended June 30,
	2024		Realization	2023		Change
NGLs (per Bbl)
WTI index	$	78.82		$	74.96		5	%
Realized price, unhedged	$	20.17	26%	$	20.79		-3	%
Cash settlements	$	0.02		$	—
Realized price, with hedges	$	20.19	26%	$	20.79		-3	%


	Six Months Ended June 30,
	2024		2023		Change
Combined (per Boe)
Realized price, unhedged	$	43.48	$	43.86		-1	%
Cash settlements	$	0.62	$	0.42
Realized price, with hedges	$	44.10	$	44.28		0	%

From the six months ended June 30, 2023 to the six months ended June 30, 2024, realized prices contributed to a $63 million increase in earnings. This increase was due to higher unhedged realized oil prices which increased primarily due to higher WTI index prices. This increase was partially offset by a decrease in unhedged realized gas prices which was primarily due to lower Henry Hub index prices. Realized prices were strengthened by hedge cash settlements related primarily to gas commodities in the first six months of 2024.

Hedge Settlements


	Six Months Ended June 30,
	2024			2023			Change
Oil	$	(12	)	$	(3	)		-300	%
Natural gas		89			53			68	%
NGL		1			—		N/M
Total cash settlements (1)	$	78		$	50			56	%

(1)

Included as a component of oil, gas and NGL derivatives on the consolidated statements of comprehensive earnings.

Production Expenses


	Six Months Ended June 30,
	2024			2023			Change
LOE	$	763		$	680			12	%
Gathering, processing & transportation		377			343			10	%
Production taxes		363			340			7	%
Property taxes		36			49			-28	%
Total	$	1,539		$	1,412			9	%
Per Boe:
LOE	$	6.12		$	5.77			6	%
Gathering, processing & transportation	$	3.02		$	2.91			4	%
Percent of oil, gas and NGL sales:
Production taxes		6.7	%		6.6	%		2	%

LOE and gathering, processing and transportation expenses increased for the first six months of 2024 primarily due to increased activity.

Field-Level Cash Margin


	Six Months Ended June 30,
	2024		$ per BOE		2023		$ per BOE
Field-level cash margin (Non-GAAP)
Delaware Basin	$	2,621	$	32.09	$	2,530	$	33.47
Eagle Ford		570	$	41.99		520	$	40.24
Anadarko Basin		217	$	15.09		265	$	17.22
Williston Basin		323	$	29.18		284	$	29.00
Powder River Basin		125	$	37.72		133	$	38.97
Other		30	N/M			28	N/M
Total	$	3,886	$	31.14	$	3,760	$	31.88

DD&A


	Six Months Ended June 30,
	2024		2023		Change
Oil and gas per Boe	$	11.56	$	10.24		13	%

Oil and gas	$	1,443	$	1,207		20	%
Other property and equipment		47		46		2	%
Total	$	1,490	$	1,253		19	%

DD&A increased in the first six months of 2024 primarily due to an increase in the oil and gas DD&A rate. The largest contributor to the higher rate was our 2023 drilling and development activity. DD&A also increased in the first six months of 2024 due to higher volumes.

G&A


	Six Months Ended June 30,
	2024		2023		Change
G&A per Boe	$	1.83	$	1.68		9	%

Labor and benefits	$	125	$	106		18	%
Non-labor		103		92		12	%
Total	$	228	$	198		15	%

G&A increased for the six months ended 2024 due to higher labor and non-labor costs.

Other Items


	Six Months Ended June 30,
	2024			2023			Change in earnings
Commodity hedge valuation changes (1)	$	(200	)	$	(62	)	$	(138	)
Marketing and midstream operations		(31	)		(39	)		8
Exploration expenses		12			13			1
Asset dispositions		16			(41	)		(57	)
Net financing costs		152			150			(2	)
Other, net		27			15			(12	)
							$	(200	)

(1)

Included as a component of oil, gas and NGL derivatives on the consolidated statements of comprehensive earnings.

In the second quarter of 2023, we recorded a $64 million gain within asset dispositions related to the difference between the fair market value and book value of assets contributed to the Water JV. For additional information, see Note 1 in "Part I. Financial Information - Item 1. Financial Statements" in this report.

Income Taxes


	Six Months Ended June 30,
	2024			2023
Current expense	$	265		$	221
Deferred expense		79			199
Total expense	$	344		$	420
Current tax rate		15	%		11	%
Deferred tax rate		4	%		9	%
Effective income tax rate		19	%		20	%

For discussion on income taxes, see Note 5 in “Part I. Financial Information – Item 1. Financial Statements” in this report.

Cap****ital Resources, Uses and Liquidity

Sources and Uses of Cash

The following table presents the major changes in cash and cash equivalents for the three and six months ended June 30, 2024 and 2023.


	Three Months Ended June 30,						Six Months Ended June 30,
	2024			2023			2024			2023
Operating cash flow	$	1,535		$	1,405		$	3,273		$	3,082
Capital expenditures		(948	)		(1,079	)		(1,842	)		(2,091	)
Acquisitions of property and equipment		(82	)		(18	)		(90	)		(31	)
Divestitures of property and equipment		1			1			18			22
Investment activity, net		10			(6	)		(26	)		(35	)
Repurchases of common stock		(256	)		(228	)		(461	)		(745	)
Common stock dividends		(223	)		(462	)		(522	)		(1,058	)
Noncontrolling interest activity, net		(7	)		(5	)		(2	)		(16	)
Other		(10	)		(7	)		(54	)		(94	)
Net change in cash, cash equivalents and restricted cash	$	20		$	(399	)	$	294		$	(966	)
Cash, cash equivalents and restricted cash at end of period	$	1,169		$	488		$	1,169		$	488

Operating Cash Flow

As presented in the table above, net cash provided by operating activities continued to be a significant source of capital and liquidity. Operating cash flow funded all of our capital expenditures, and we continued to return value to our shareholders by utilizing cash flow and cash balances for dividends and share repurchases.

Capital Expenditures

The amounts in the table below reflect cash payments for capital expenditures, including cash paid for capital expenditures incurred in prior periods.


	Three Months Ended June 30,				Six Months Ended June 30,
	2024		2023		2024		2023
Delaware Basin	$	539	$	644	$	1,073	$	1,228
Eagle Ford		202		198		359		390
Anadarko Basin		59		79		119		141
Williston Basin		42		83		84		182
Powder River Basin		53		41		86		79
Other		1		1		3		2
Total oil and gas		896		1,046		1,724		2,022
Midstream		30		18		67		34
Other		22		15		51		35
Total capital expenditures	$	948	$	1,079	$	1,842	$	2,091

Capital expenditures consist primarily of amounts related to our oil and gas exploration and development operations, midstream operations and other corporate activities. Our capital investment program is driven by a disciplined allocation process focused on moderating our production growth and maximizing our returns. As such, our capital expenditures for the first six months of 2024 represented approximately 56% of our operating cash flow.

Acquisitions of Property and Equipment

During the first six months of 2024, we acquired leasehold interests across our portfolio, including in the Delaware Basin.

Divestitures of Property and Equipment

During the first six months of 2024 and 2023, we received contingent earnout payments related to assets previously sold. For additional information, please see Note 2 in “Part I. Financial Information – Item 1. Financial Statements” in this report.

Investment Activity

During the first six months of 2024 and 2023, Devon received distributions from our investments of $22 million and $17 million, respectively. Devon contributed $48 million and $52 million to our investments during the first six months of 2024 and 2023, respectively.

Shareholder Distributions and Stock Activity

We repurchased approximately 9.6 million shares of common stock for $449 million and approximately 13.9 million shares of common stock for $745 million under the share repurchase program authorized by our Board of Directors in the first six months of 2024 and 2023, respectively. For additional information, see Note 14 in “Part I. Financial Information – Item 1. Financial Statements” in this report.

The following table summarizes our common stock dividends during the second quarter and total for the first six months of 2024 and 2023. Devon has raised its fixed dividend multiple times over the past two calendar years and most recently raised it by 10% from $0.20 to $0.22 per share in the first quarter of 2024. In addition to the fixed quarterly dividend, we paid a variable dividend in the first and second quarters of 2024 and 2023.


	Fixed		Variable		Total		Rate Per Share
2024:
First quarter	$	143	$	156	$	299	$	0.44
Second quarter		138		85		223	$	0.35
Total year-to-date	$	281	$	241	$	522
2023:
First quarter	$	133	$	463	$	596	$	0.89
Second quarter		128		334		462	$	0.72
Total year-to-date	$	261	$	797	$	1,058

Noncontrolling Interest Activity, net

During the first six months of 2024 and 2023, we distributed $26 million and $24 million, respectively, to our noncontrolling interests in CDM. During the first six months of 2024 and 2023, we received $24 million and $8 million, respectively, in contributions from our noncontrolling interests.

Liquidity

The business of exploring for, developing and producing oil and natural gas is capital intensive. Because oil, natural gas and NGL reserves are a depleting resource, we, like all upstream operators, must continually make capital investments to grow and even sustain production. Generally, our capital investments are focused on drilling and completing new wells and maintaining production from existing wells. At opportunistic times, we also acquire operations and properties from other operators or landowners to enhance our existing portfolio of assets.

Historically, our primary sources of capital funding and liquidity have been our operating cash flow, cash on hand and asset divestiture proceeds. Additionally, we maintain a commercial paper program, supported by our revolving line of credit, which can be accessed as needed to supplement operating cash flow and cash balances. If needed, we can also issue debt and equity securities, including through transactions under our shelf registration statement filed with the SEC. We estimate the combination of our sources of capital will continue to be adequate to fund our planned capital requirements as discussed in this section as well as accelerate our cash-return business model.

Operating Cash Flow

Key inputs into determining our planned capital investment are the amount of cash we hold and operating cash flow we expect to generate over the next one to three or more years. At the end of the second quarter of 2024, we held approximately $1.2 billion of cash. Our operating cash flow forecasts are sensitive to many variables and include a measure of uncertainty as actual results may differ from our expectations.

Commodity Prices – The most uncertain and volatile variables for our operating cash flow are the prices of the oil, gas and NGLs we produce and sell. Prices are determined primarily by prevailing market conditions. Regional and worldwide economic

activity, weather and other highly variable factors influence market conditions for these products. These factors, which are difficult to predict, create volatility in prices and are beyond our control.

To mitigate some of the risk inherent in prices, we utilize various derivative financial instruments to protect a portion of our production against downside price risk. The key terms to our oil, gas and NGL derivative financial instruments as of June 30, 2024 are presented in Note 3 in “Part I. Financial Information – Item 1. Financial Statements” of this report.

Further, when considering the current commodity price environment and our current hedge position, we expect to achieve our capital investment priorities. Additionally, we remain committed to capital discipline and focused on delivering the objectives that underpin our capital plan for 2024. The currently elevated level of cost inflation has eroded, and could continue to erode, our cost efficiencies gained over previous years and pressure our margins for the remainder of 2024. Despite this, we expect to continue generating material amounts of free cash flow at current commodity price levels due to our strategy of spending within cash flow.

Operating Expenses – Commodity prices can also affect our operating cash flow through an indirect effect on operating expenses. Significant commodity price decreases can lead to a decrease in drilling and development activities. As a result, the demand and cost for people, services, equipment and materials may also decrease, causing a positive impact on our cash flow as the prices paid for services and equipment decline. However, the inverse is also generally true during periods of rising commodity prices. We expect to mitigate the impact of cost inflation through efficiencies gained from the scale of our operations as well as by leveraging our long-standing relationships with our suppliers.

Credit Losses – Our operating cash flow is also exposed to credit risk in a variety of ways. This includes the credit risk related to customers who purchase our oil, gas and NGL production, the collection of receivables from our joint interest owners for their proportionate share of expenditures made on projects we operate and counterparties to our derivative financial contracts. We utilize a variety of mechanisms to limit our exposure to the credit risks of our customers, joint interest owners and counterparties. Such mechanisms include, under certain conditions, requiring letters of credit, prepayments or cash collateral postings.

Credit Availability

As of June 30, 2024, we had approximately $3.0 billion of available borrowing capacity under our 2023 Senior Credit Facility. This credit facility supports our $3.0 billion of short-term credit under our commercial paper program. At June 30, 2024, there were no borrowings under our commercial paper program, and we were in compliance with the Senior Credit Facility’s financial covenant.

Debt Ratings

We receive debt ratings from the major ratings agencies in the U.S. In determining our debt ratings, the agencies consider a number of qualitative and quantitative items including, but not limited to, commodity pricing levels, our liquidity, asset quality, reserve mix, debt levels, cost structure, planned asset sales and the size and scale of our production. Our credit rating from Standard and Poor’s Financial Services is BBB with a stable outlook. Our credit rating from Fitch is BBB+ with a stable outlook. Our credit rating from Moody’s Investor Service is Baa2 with a stable outlook. Any rating downgrades may result in additional letters of credit or cash collateral being posted under certain contractual arrangements.

There are no “rating triggers” in any of our contractual debt obligations that would accelerate scheduled maturities should our debt rating fall below a specified level. However, a downgrade could adversely impact our interest rate on any credit facility borrowings and the ability to economically access debt markets in the future.

Cash Returns to Shareholders

We are committed to returning approximately 70% of our free cash flow to shareholders through a fixed dividend, variable dividend and share repurchases. Our Board of Directors will consider a number of factors when setting the quarterly dividend, if any, including a general target of paying out approximately 10% of operating cash flow through the fixed dividend. In addition to the fixed quarterly dividend, we may pay a variable dividend or complete share repurchases. Each quarter’s free cash flow, which is a non-GAAP measure, is computed as operating cash flow (a GAAP measure) before balance sheet changes less capital expenditures. The declaration and payment of any future dividend, whether fixed or variable, will remain at the full discretion of our Board of Directors and will depend on our financial results, cash requirements, future prospects and other factors deemed relevant by the Board.

In August 2024, Devon announced a cash dividend in the amount of $0.44 per share payable in the third quarter of 2024. The dividend consists of a $0.22 per share fixed quarterly dividend and a $0.22 per share variable quarterly dividend and will total approximately $276 million.

Our Board of Directors has authorized a $5.0 billion share repurchase program that expires June 30, 2026. Through July 2024, we had executed $2.8 billion of the authorized program.

Capital Expenditures

Our capital expenditures budget for the remainder of 2024 is expected to range from approximately $1.4 billion to $1.7 billion. These ranges do not include the potential impact of the Grayson Mill Energy acquisition that is expected to close by the end of the third quarter of 2024.

Acquisition

Critical Accounting Est****imates

For information regarding our critical accounting policies and estimates, see our 2023 Annual Report on Form 10-K.

Non-GA****AP Measures

We utilize “core earnings attributable to Devon” and “core earnings per share attributable to Devon” that are not required by or presented in accordance with GAAP. These non-GAAP measures are not alternatives to GAAP measures and should not be considered in isolation or as a substitute for analysis of our results reported under GAAP. Core earnings attributable to Devon, as well as the per share amount, represent net earnings excluding certain non-cash and other items that are typically excluded by securities analysts in their published estimates of our financial results. Our non-GAAP measures are typically used as a quarterly performance measure. Amounts excluded relate to asset dispositions, noncash asset impairments (including unproved asset impairments), deferred tax asset valuation allowance and fair value changes in derivative financial instruments.

We believe these non-GAAP measures facilitate comparisons of our performance to earnings estimates published by securities analysts. We also believe these non-GAAP measures can facilitate comparisons of our performance between periods and to the performance of our peers.

Below are reconciliations of core earnings and core earnings per share attributable to Devon to comparable GAAP measures.


	Three Months Ended June 30,												Six Months Ended June 30,
	Before Tax			After Tax			After NCI			Per Diluted Share			Before Tax			After Tax			After NCI			Per Diluted Share
2024:
Earnings attributable to Devon (GAAP)	$	1,040		$	855		$	844		$	1.34		$	1,808		$	1,464		$	1,440		$	2.29
Adjustments:
Asset dispositions		15			11			11			0.02			16			12			12			0.02
Asset and exploration impairments		1			1			1			—			1			1			1			—
Deferred tax asset valuation allowance		—			4			4			0.01			—			3			3			—
Fair value changes in financial instruments		32			25			25			0.04			204			159			159			0.25
Core earnings attributable to Devon (Non-GAAP)	$	1,088		$	896		$	885		$	1.41		$	2,029		$	1,639		$	1,615		$	2.56
2023:
Earnings attributable to Devon (GAAP)	$	897		$	698		$	690		$	1.07		$	2,121		$	1,701		$	1,685		$	2.60
Adjustments:
Asset dispositions		(41	)		(31	)		(31	)		(0.05	)		(41	)		(31	)		(31	)		(0.05	)
Asset and exploration impairments		3			2			2			0.01			3			2			2			0.01
Deferred tax asset valuation allowance		—			10			10			0.02			—			7			7			0.01
Fair value changes in financial instruments		112			84			84			0.13			59			44			44			0.07
Core earnings attributable to Devon (Non-GAAP)	$	971		$	763		$	755		$	1.18		$	2,142		$	1,723		$	1,707		$	2.64

EBITDAX and Field-Level Cash Margin

To assess the performance of our assets, we use EBITDAX and Field-Level Cash Margin. We compute EBITDAX as net earnings before income tax expense; financing costs, net; exploration expenses; DD&A; asset impairments; asset disposition gains and losses; non-cash share-based compensation; non-cash valuation changes for derivatives and financial instruments; restructuring and transaction costs; accretion on discounted liabilities; and other items not related to our normal operations. Field-Level Cash Margin is computed as oil, gas and NGL sales less production expenses. Production expenses consist of lease operating, gathering, processing and transportation expenses, as well as production and property taxes.

We exclude financing costs from EBITDAX to assess our operating results without regard to our financing methods or capital structure. Exploration expenses and asset disposition gains and losses are excluded from EBITDAX because they generally are not indicators of operating efficiency for a given reporting period. DD&A and impairments are excluded from EBITDAX because capital expenditures are evaluated at the time capital costs are incurred. We exclude share-based compensation, valuation changes, restructuring and transaction costs, accretion on discounted liabilities and other items from EBITDAX because they are not considered a measure of asset operating performance.

We believe EBITDAX and Field-Level Cash Margin provide information useful in assessing our operating and financial performance across periods. EBITDAX and Field-Level Cash Margin as defined by Devon may not be comparable to similarly titled measures used by other companies and should be considered in conjunction with net earnings from operations.

Below are reconciliations of net earnings to EBITDAX and a further reconciliation to Field-Level Cash Margin.


	Three Months Ended June 30,						Six Months Ended June 30,
	2024			2023			2024			2023
Net earnings (GAAP)	$	855		$	698		$	1,464		$	1,701
Financing costs, net		76			78			152			150
Income tax expense		185			199			344			420
Exploration expenses		3			10			12			13
Depreciation, depletion and amortization		768			638			1,490			1,253
Asset dispositions		15			(41	)		16			(41	)
Share-based compensation		26			25			50			48
Derivative and financial instrument non-cash valuation changes		31			113			200			62
Accretion on discounted liabilities and other		5			10			27			15
EBITDAX (Non-GAAP)		1,964			1,730			3,755			3,621
Marketing and midstream revenues and expenses, net		10			14			31			39
Commodity derivative cash settlements		(54	)		(37	)		(78	)		(50	)
General and administrative expenses, cash-based		88			67			178			150
Field-level cash margin (Non-GAAP)	$	2,008		$	1,774		$	3,886		$	3,760

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