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 nine-month periods ended September 30, 2023 compared to previous periods and in our financial condition and liquidity since December 31, 2022. For information regarding our critical accounting policies and estimates, see our 2022 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 provide a deep inventory of opportunities for years to come. In the third quarter of 2022, we acquired additional producing properties and leasehold interests in both the Williston Basin and Eagle Ford that were complementary to our existing acreage, offered operational synergies and added additional high-quality inventory to our portfolio.

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:

Third quarter oil production totaled 321 MBbls/d, which is a 9% increase year over year.

As of September 30, 2023, completed approximately 68% of our authorized $3.0 billion share repurchase program, with approximately 39.6 million of our common shares repurchased for approximately $2.1 billion, or $51.86 per share since inception of the plan.

Retired $242 million of senior notes in the third quarter.

Exited the third quarter with $3.8 billion of liquidity, including $0.8 billion of cash.

Generated $1.7 billion of operating cash flow in the third quarter of 2023 and $6.7 billion for the past twelve trailing months.

Including variable dividends, paid dividends of $312 million in the third quarter of 2023 and have declared approximately $492 million of dividends to be paid in the fourth quarter of 2023.

Third quarter earnings attributable to Devon were $910 million, or $1.42 per diluted share.

Third quarter core earnings (Non-GAAP) were $1.1 billion, or $1.65 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.

Q3 2023 vs. Q2 2023

Our third quarter 2023 and second quarter 2023 net earnings were $920 million and $698 million, respectively. The graph below shows the change in net earnings from the second quarter of 2023 to the third quarter of 2023. The material changes are further discussed by category on the following pages.

Production Volumes

		Q3 2023				% of Total				Q2 2023				Change
Oil (MBbls/d)
Delaware Basin			215				67	%			209				3	%
Eagle Ford			40				13	%			45				-10	%
Anadarko Basin			14				4	%			15				-11	%
Williston Basin			35				11	%			36				-2	%
Powder River Basin			13				4	%			14				-3	%
Other			4				1	%			4				-1	%
Total			321				100	%			323				-1	%

		Q3 2023				% of Total				Q2 2023				Change
Gas (MMcf/d)
Delaware Basin			680				64	%			636				7	%
Eagle Ford			78				7	%			86				-9	%
Anadarko Basin			235				22	%			254				-7	%
Williston Basin			58				5	%			59				-2	%
Powder River Basin			18				2	%			18				0	%
Other			1				0	%			1				1	%
Total			1,070				100	%			1,054				2	%

		Q3 2023				% of Total				Q2 2023				Change
NGLs (MBbls/d)
Delaware Basin			112				67	%			105				6	%
Eagle Ford			15				9	%			16				-6	%
Anadarko Basin			27				16	%			31				-12	%
Williston Basin			9				6	%			9				0	%
Powder River Basin			2				1	%			2				3	%
Other			1				1	%			1				-14	%
Total			166				100	%			164				1	%

		Q3 2023				% of Total				Q2 2023				Change
Combined (MBoe/d)
Delaware Basin			440				66	%			420				5	%
Eagle Ford			68				10	%			74				-9	%
Anadarko Basin			80				12	%			89				-10	%
Williston Basin			54				8	%			56				-2	%
Powder River Basin			19				3	%			19				-2	%
Other			4				1	%			4				1	%
Total			665				100	%			662				0	%

From the second quarter of 2023 to the third quarter of 2023, the change in volumes contributed to a $21 million increase to earnings. The slight increase in volumes was primarily due to new well activity in the Delaware Basin which was partially offset by natural well declines in the Anadarko Basin and Eagle Ford.

Realized Prices

		Q3 2023				Realization		Q2 2023				Change
Oil (per Bbl)
WTI index		$	82.06					$	73.76				11	%
Realized price, unhedged		$	80.48			98%		$	71.74				12	%
Cash settlements		$	(0.67	)				$	—
Realized price, with hedges		$	79.81			97%		$	71.74				11	%

		Q3 2023				Realization		Q2 2023				Change
Gas (per Mcf)
Henry Hub index		$	2.54					$	2.09				22	%
Realized price, unhedged		$	1.92			76%		$	1.27				52	%
Cash settlements		$	0.09					$	0.39
Realized price, with hedges		$	2.01			79%		$	1.66				21	%

		Q3 2023				Realization		Q2 2023				Change
NGLs (per Bbl)
WTI index		$	82.06					$	73.76				11	%
Realized price, unhedged		$	20.72			25%		$	17.79				16	%
Cash settlements		$	—					$	—
Realized price, with hedges		$	20.72			25%		$	17.79				16	%

		Q3 2023				Q2 2023				Change
Combined (per Boe)
Realized price, unhedged		$	47.10			$	41.39				14	%
Cash settlements		$	(0.18	)		$	0.61
Realized price, with hedges		$	46.92			$	42.00				12	%

From the second quarter of 2023 to the third quarter of 2023, realized prices contributed to a $368 million increase in earnings. Unhedged realized oil, gas and NGL prices increased primarily due to higher WTI, Henry Hub and Mont Belvieu index prices. The increase in index prices was partially offset by hedge cash settlement payments related to oil commodities.

We currently have hedged approximately 35% and 30% of our remaining anticipated 2023 oil and gas production, respectively. For 2024, we currently have hedged approximately 30% and 20% of our anticipated oil and gas production, respectively.

Hedge Settlements

		Q3 2023				Q2 2023				Change
		Q
Oil		$	(20	)		$	—			N/M
Natural gas			9				37				-76	%
Total cash settlements (1)		$	(11	)		$	37				-130	%

(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

		Q3 2023				Q2 2023				Change
LOE		$	367			$	353				4	%
Gathering, processing & transportation			178				177				1	%
Production taxes			191				165				16	%
Property taxes			21				24				-13	%
Total		$	757			$	719				5	%
Per Boe:
LOE		$	6.00			$	5.86				2	%
Gathering, processing & transportation		$	2.91			$	2.94				-1	%
Percent of oil, gas and NGL sales:
Production taxes			6.6	%			6.6	%			0	%

Production expenses increased in the third quarter of 2023 primarily due to an increase in production taxes which resulted from higher commodity prices. Additionally, LOE increased primarily due to an increase in activity in the Delaware Basin.

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.

		Q3 2023				$ per BOE				Q2 2023				$ per BOE
Field-level cash margin (Non-GAAP)
Delaware Basin		$	1,479			$	36.54			$	1,196			$	31.28
Eagle Ford			269			$	43.38				263			$	38.87
Anadarko Basin			125			$	16.98				111			$	13.72
Williston Basin			161			$	32.16				128			$	25.54
Powder River Basin			75			$	43.29				63			$	36.54
Other			16			N/M					13			N/M
Total		$	2,125			$	34.73			$	1,774			$	29.45

DD&A

		Q3 2023				Q2 2023				Change
Oil and gas per Boe		$	10.27			$	10.22				0	%
Oil and gas		$	629			$	616				2	%
Other property and equipment			22				22				-1	%
Total		$	651			$	638				2	%

G&A

		Q3 2023				Q2 2023				Change
G&A per Boe		$	1.60			$	1.52				5	%
Labor and benefits		$	51			$	50				3	%
Non-labor			48				42				12	%
Total		$	99			$	92				7	%

G&A increased marginally in the third quarter of 2023 primarily due to higher non-labor costs.

Other Items

		Q3 2023				Q2 2023				Change in earnings
Commodity hedge valuation changes (1)		$	(183	)		$	(113	)		$	(70	)
Marketing and midstream operations			(12	)			(14	)			2
Exploration expenses			3				10				7
Asset dispositions			—				(41	)			(41	)
Net financing costs			81				78				(3	)
Other, net			13				10				(3	)
										$	(108	)

(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.

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

		Q3 2023				Q2 2023
Current expense		$	139			$	80
Deferred expense			13				119
Total expense		$	152			$	199
Current tax rate			13	%			9	%
Deferred tax rate			1	%			13	%
Effective income tax rate			14	%			22	%

We continue to analyze the new CAMT and its effects on our tax planning. Our current rate is trending below the 15% stated rate in the CAMT primarily due to utilization of tax credits. For further discussion on income taxes, see Note 7 in “Part I. Financial Information – Item 1. Financial Statements” in this report.

September 30, 2023 YTD vs. September 30, 2022 YTD

Our nine months ended September 30, 2023 net earnings were $2.6 billion, compared to net earnings of $4.8 billion for the first nine months ended September 30, 2022. The graph below shows the change in net earnings from the nine months ended September 30, 2022 to the nine months ended September 30, 2023. The material changes are further discussed by category on the following pages.

Production Volumes

		Nine Months Ended September 30,
		2023				% of Total				2022				Change
Oil (MBbls/d)
Delaware Basin			211				66	%			214				-1	%
Eagle Ford			41				13	%			18				129	%
Anadarko Basin			15				5	%			14				7	%
Williston Basin			36				11	%			31				14	%
Powder River Basin			14				4	%			13				6	%
Other			4				1	%			4				-7	%
Total			321				100	%			294				9	%

		Nine Months Ended September 30,
		2023				% of Total				2022				Change
Gas (MMcf/d)
Delaware Basin			652				62	%			601				9	%
Eagle Ford			82				8	%			62				32	%
Anadarko Basin			242				23	%			215				12	%
Williston Basin			57				5	%			59				-4	%
Powder River Basin			18				2	%			18				-4	%
Other			1				0	%			1				30	%
Total			1,052				100	%			956				10	%

		Nine Months Ended September 30,
		2023				% of Total				2022				Change
NGLs (MBbls/d)
Delaware Basin			105				66	%			104				1	%
Eagle Ford			15				9	%			9				62	%
Anadarko Basin			28				18	%			26				10	%
Williston Basin			9				6	%			8				8	%
Powder River Basin			2				1	%			2				-1	%
Other			1				0	%			—			N/M
Total			160				100	%			149				7	%

		Nine Months Ended September 30,
		2023				% of Total				2022				Change
Combined (MBoe/d)
Delaware Basin			425				65	%			417				2	%
Eagle Ford			70				10	%			38				87	%
Anadarko Basin			83				13	%			75				11	%
Williston Basin			54				8	%			50				9	%
Powder River Basin			19				3	%			18				3	%
Other			5				1	%			4				2	%
Total			656				100	%			602				9	%

From the nine months ended 2022 to the nine months ended 2023, the change in volumes contributed to a $1.0 billion increase in earnings. Volumes increased primarily due to acquisitions in the Eagle Ford and Williston Basin which both closed in the third quarter of 2022. Volumes also increased due to new well activity in the Delaware Basin and Anadarko Basin.

Realized Prices

		Nine Months Ended September 30,
		2023				Realization		2022				Change
Oil (per Bbl)
WTI index		$	77.33					$	98.34				-21	%
Realized price, unhedged		$	75.53			98%		$	98.39				-23	%
Cash settlements		$	(0.26	)				$	(11.02	)
Realized price, with hedges		$	75.27			97%		$	87.37				-14	%

		Nine Months Ended September 30,
		2023				Realization		2022				Change
Gas (per Mcf)
Henry Hub index		$	2.69					$	6.78				-60	%
Realized price, unhedged		$	1.82			68%		$	5.86				-69	%
Cash settlements		$	0.22					$	(1.12	)
Realized price, with hedges		$	2.04			76%		$	4.74				-57	%

		Nine Months Ended September 30,
		2023				Realization		2022				Change
NGLs (per Bbl)
WTI index		$	77.33					$	98.34				-21	%
Realized price, unhedged		$	20.76			27%		$	37.48				-45	%
Cash settlements		$	—					$	—
Realized price, with hedges		$	20.76			27%		$	37.48				-45	%

		Nine Months Ended September 30,
		2023				2022				Change
Combined (per Boe)
Realized price, unhedged		$	44.96			$	66.60				-32	%
Cash settlements		$	0.22			$	(7.17	)
Realized price, with hedges		$	45.18			$	59.43				-24	%

From the nine months ended 2022 to the nine months ended 2023, realized prices contributed to a $3.9 billion decrease in earnings. Unhedged realized oil, gas and NGL prices decreased primarily due to lower WTI, Henry Hub and Mont Belvieu index prices. The decrease in index prices was partially offset by improved hedge cash settlements related to oil and gas commodities.

Hedge Settlements

		Nine Months Ended September 30,
		2023				2022				Change
Oil		$	(23	)		$	(884	)			97	%
Natural gas			62				(295	)			121	%
Total cash settlements (1)		$	39			$	(1,179	)			103	%

(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

		Nine Months Ended September 30,
		2023				2022				Change
LOE		$	1,047			$	763				37	%
Gathering, processing & transportation			521				515				1	%
Production taxes			531				744				-29	%
Property taxes			70				60				16	%
Total		$	2,169			$	2,082				4	%
Per Boe:
LOE		$	5.84			$	4.65				26	%
Gathering, processing & transportation		$	2.91			$	3.13				-7	%
Percent of oil, gas and NGL sales:
Production taxes			6.6	%			6.8	%			-3	%

LOE expenses and LOE per Boe increased for the nine months ended 2023 primarily due to acquisitions in the Eagle Ford and Williston Basin as well as cost inflation. Production taxes decreased due to lower commodity 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.

		Nine Months Ended September 30,
		2023				$ per BOE				2022				$ per BOE
Field-level cash margin (Non-GAAP)
Delaware Basin		$	4,009			$	34.54			$	6,488			$	57.01
Eagle Ford			789			$	41.26				549			$	53.56
Anadarko Basin			390			$	17.14				765			$	37.24
Williston Basin			445			$	30.06				673			$	49.87
Powder River Basin			208			$	40.41				302			$	60.65
Other			44			N/M					84			N/M
Total		$	5,885			$	32.86			$	8,861			$	53.93

DD&A

		Nine Months Ended September 30,
		2023				2022				Change
Oil and gas per Boe		$	10.25			$	9.30				10	%
Oil and gas		$	1,836			$	1,528				20	%
Other property and equipment			68				70				-3	%
Total		$	1,904			$	1,598				19	%

DD&A and our oil and gas per Boe rate both increased for the nine months ended 2023 primarily due to acquisitions in the Eagle Ford and Williston Basin which both closed in the third quarter of 2022.

G&A

		Nine Months Ended September 30,
		2023				2022				Change
G&A per Boe		$	1.66			$	1.67				-1	%
Labor and benefits		$	157			$	156				1	%
Non-labor			140				117				19	%
Total		$	297			$	273				8	%

G&A increased for the nine months ended 2023 primarily due to an increase in non-labor costs.

Other Items

		Nine Months Ended September 30,
		2023				2022				Change in earnings
Commodity hedge valuation changes (1)		$	(245	)		$	574			$	(819	)
Marketing and midstream operations			(51	)			(17	)			(34	)
Exploration expenses			16				16				-
Asset dispositions			(41	)			(15	)			26
Net financing costs			231				236				5
Other, net			28				(91	)			(119	)
										$	(941	)

(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.

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.

For discussion on other, net, see Note 6 in “Part I. Financial Information – Item 1. Financial Statements” in this report.

Income Taxes

		Nine Months Ended September 30,
		2023				2022
Current expense		$	360			$	475
Deferred expense			212				914
Total expense		$	572			$	1,389
Current tax rate			11	%			7	%
Deferred tax rate			7	%			15	%
Effective income tax rate			18	%			22	%

We continue to analyze the new CAMT and its effects on our tax planning. Our current rate is trending below the 15% stated rate in the CAMT primarily due to utilization of tax credits. For further discussion on income taxes, see Note 7 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 nine months ended September 30, 2023 and 2022.

		Three Months Ended September 30,								Nine Months Ended September 30,
		2023				2022				2023				2022
Operating cash flow		$	1,725			$	2,104			$	4,807			$	6,619
Capital expenditures			(882	)			(628	)			(2,973	)			(1,738	)
Acquisitions of property and equipment			(23	)			(2,465	)			(54	)			(2,566	)
Divestitures of property and equipment			1				4				23				39
Investment activity, net			7				(9	)			(28	)			(29	)
Debt activity, net			(242	)			—				(242	)			—
Repurchases of common stock			—				(126	)			(745	)			(661	)
Common stock dividends			(312	)			(1,007	)			(1,370	)			(2,504	)
Noncontrolling interest activity, net			1				(9	)			(15	)			(22	)
Shares traded for taxes and other			(2	)			(11	)			(96	)			(99	)
Net change in cash, cash equivalents and restricted cash		$	273			$	(2,147	)		$	(693	)		$	(961	)
Cash, cash equivalents and restricted cash at end of period		$	761			$	1,310			$	761			$	1,310

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, share repurchases and debt repayments.

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 September 30,								Nine Months Ended September 30,
		2023				2022				2023				2022
Delaware Basin		$	507			$	409			$	1,735			$	1,216
Eagle Ford			183				36				573				95
Anadarko Basin			22				50				163				92
Williston Basin			82				48				264				87
Powder River Basin			46				52				125				113
Other			2				2				4				8
Total oil and gas			842				597				2,864				1,611
Midstream			17				17				51				74
Other			23				14				58				53
Total capital expenditures		$	882			$	628			$	2,973			$	1,738

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 nine months of 2023 represented approximately 62% of our operating cash flow. Capital expenditures increased due to acquisitions, general inflation trends and expanded development in the Delaware and Anadarko Basins.

Acquisitions of Property and Equipment

During the first nine months of 2022, we paid $2.6 billion toward acquisitions of production properties and leasehold interests located in the Eagle Ford and Williston Basin, which were completed in the third quarter of 2022. For additional information, please see Note 2 in “Part I. Financial Information – Item 1. Financial Statements” in this report.

Divestitures of Property and Equipment

During the first nine months of 2023 and 2022, 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 nine months of both 2023 and 2022, Devon received distributions from our investments of $24 million and $30 million, respectively. Devon contributed $52 million and $59 million to our investments during the first nine months of 2023 and 2022, respectively.

Debt Activity

During 2023, we repaid $242 million of senior notes at maturity.

Shareholder Distributions and Stock Activity

We repurchased approximately 13.9 million shares of common stock for $745 million and approximately 11 million shares of common stock for $661 million, under the share repurchase program authorized by our Board of Directors, in the first nine months of 2023 and 2022, respectively. For additional information, see Note 16 in “Part I. Financial Information – Item 1. Financial Statements” in this report.

The following table summarizes our common stock dividends during the third quarter and total for the first nine months of 2023 and 2022. Devon has raised its fixed dividend multiple times over the past two calendar years to $0.20 per share beginning in the first quarter of 2023. In addition to the fixed quarterly dividend, we paid a variable dividend in the first, second and third quarters of 2023 and 2022.

	Fixed				Variable				Total				Rate Per Share
2023:
First quarter	$	133			$	463			$	596			$	0.89
Second quarter		128				334				462			$	0.72
Third quarter		127				185				312			$	0.49
Total year-to-date	$	388			$	982			$	1,370
2022:
First quarter	$	109			$	558			$	667			$	1.00
Second quarter		105				725				830			$	1.27
Third quarter		117				890				1,007			$	1.55
Total year-to-date	$	331			$	2,173			$	2,504

Noncontrolling Interest Activity, net

During the first nine months of 2023 and 2022, we distributed $33 million and $22 million, respectively, to our noncontrolling interests in CDM. During the first nine months of 2023, we received contributions from our noncontrolling interests of $18 million.

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 third quarter of 2023, we held approximately $0.8 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 September 30, 2023 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 2023. The currently elevated level of cost inflation has eroded, and could continue to erode, the cost efficiencies gained over previous years and further pressure our margins for the remainder of 2023 and into 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 September 30, 2023, 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 September 30, 2023, 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.

Fixed Plus Variable Dividend

We have a “fixed plus variable” dividend strategy. 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. Our Board of Directors increased our quarterly fixed dividend rate by 11% to $0.20 per share beginning in February 2023. In addition to the fixed quarterly dividend, we may pay a variable dividend of up to 50% of our excess free cash flow, which is a non-GAAP measure. Each quarter’s excess free cash flow is computed as operating cash flow (a GAAP measure) before balance sheet changes, less capital expenditures and the fixed dividend. 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 November 2023, Devon announced a cash dividend in the amount of $0.77 per share payable in the fourth quarter of 2023. The dividend consists of a $0.20 per share fixed quarterly dividend and a $0.57 per share variable quarterly dividend and will total approximately $492 million.

Share Repurchases

In May 2023, our Board of Directors increased our share repurchase program by $1.0 billion to a total authorized amount of $3.0 billion and extended the expiration date to December 31, 2024. Through October 2023, we had executed $2.1 billion of the authorized program.

Capital Expenditures

Our capital expenditures budget for the remainder of 2023 is expected to be approximately $900 million.

Critical Accounting Est****imates

Income Taxes

The amount of income taxes recorded requires interpretations of complex rules and regulations of federal, state, provincial and foreign tax jurisdictions. We recognize current tax expense based on estimated taxable income for the current period and the applicable statutory tax rates. We routinely assess potential uncertain tax positions and, if required, estimate and establish accruals for such amounts. We have recognized deferred tax assets and liabilities for temporary differences, operating losses and other tax carryforwards. We routinely assess our deferred tax assets and reduce such assets by a valuation allowance if we deem it is more likely than not that some portion or all of the deferred tax assets will not be realized.

Further, in the event we were to undergo an “ownership change” (as defined in Section 382 of the Internal Revenue Code of 1986, as amended), our ability to use net operating losses and tax credits generated prior to the ownership change may be limited. Generally, an “ownership change” occurs if one or more shareholders, each of whom owns five percent or more in value of a corporation’s stock, increase their aggregate percentage ownership by more than 50 percent over the lowest percentage of stock owned by those shareholders at any time during the preceding three-year period. Based on currently available information, we do not believe an ownership change has occurred during the first nine months of 2023 for Devon, but the Merger did cause an ownership change for WPX and increased the likelihood Devon could experience an ownership change over the next year.

On August 16, 2022, the IRA was signed into law and included various income tax related provisions with an effective date beginning in 2023. Among the enacted provisions are a 15% CAMT and several new and expanded clean energy credits and incentives. Devon believes it is subject to the CAMT as Devon has an average annual AFSI that exceeds $1 billion for the three-year period ended December 31, 2022. Devon continues to assess the potential incremental cash tax that could be incurred, depending on actual operating results, as well as ongoing U.S. Treasury guidance.

For additional information regarding our critical accounting policies and estimates, see our 2022 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 September 30,																Nine Months Ended September 30,
	Before Tax				After Tax				After NCI				Per Diluted Share				Before Tax				After Tax				After NCI				Per Diluted Share
2023
Earnings attributable to Devon (GAAP)	$	1,072			$	920			$	910			$	1.42			$	3,193			$	2,621			$	2,595			$	4.03
Adjustments:
Asset dispositions		—				—				—				—				(41	)			(31	)			(31	)			(0.05	)
Asset and exploration impairments		—				—				—				—				3				2				2				0.01
Deferred tax asset valuation allowance		—				3				3				—				—				10				10				0.02
Fair value changes in financial instruments		186				145				145				0.23				245				189				189				0.29
Core earnings attributable to Devon (Non-GAAP)	$	1,258			$	1,068			$	1,058			$	1.65			$	3,400			$	2,791			$	2,765			$	4.30
2022
Earnings attributable to Devon (GAAP)	$	2,465			$	1,900			$	1,893			$	2.88			$	6,222			$	4,833			$	4,814			$	7.28
Adjustments:
Asset dispositions		—				—				—				—				(15	)			(12	)			(12	)			(0.02	)
Asset and exploration impairments		1				1				1				—				9				7				7				0.01
Deferred tax asset valuation allowance		—				(1	)			(1	)			—				—				15				15				0.02
Fair value changes in financial instruments		(604	)			(464	)			(464	)			(0.70	)			(565	)			(433	)			(433	)			(0.65	)
Core earnings attributable to Devon (Non-GAAP)	$	1,862			$	1,436			$	1,429			$	2.18			$	5,651			$	4,410			$	4,391			$	6.64

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 September 30,								Nine Months Ended September 30,
		2023				2022				2023				2022
Net earnings (GAAP)		$	920			$	1,900			$	2,621			$	4,833
Financing costs, net			81				67				231				236
Income tax expense			152				565				572				1,389
Exploration expenses			3				4				16				16
Depreciation, depletion and amortization			651				581				1,904				1,598
Asset dispositions			—				—				(41	)			(15	)
Share-based compensation			22				22				70				64
Derivative and financial instrument non-cash valuation changes			183				(613	)			245				(576	)
Accretion on discounted liabilities and other			13				(38	)			28				(89	)
EBITDAX (Non-GAAP)			2,025				2,488				5,646				7,456
Marketing and midstream revenues and expenses, net			12				9				51				17
Commodity derivative cash settlements			11				363				(39	)			1,179
General and administrative expenses, cash-based			77				73				227				209
Field-level cash margin (Non-GAAP)		$	2,125			$	2,933			$	5,885			$	8,861